Indicate by check mark if the registrant is a well-known seasoned
issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [ X ]

Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [ X ]

Indicate by check mark whether the registrant has submitted electronically
and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule
405 of Regulation S-T during the preceding twelve months (or for such shorter period that the registrant was required to submit
and post such files). Yes [ X ] No [ ]

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes [ X ] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K (§293.405 of this chapter) is not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of the Form 10-K
or any amendment to this Form 10-K. [ X ]

-1-

Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer or a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated
filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check
one):

Large accelerated filer [ ] Accelerated filer
[ ]

Non-accelerated filer [ ] Smaller reporting company
[ X ]

Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Exchange Act. Yes [ ] No [ X ]

State the aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal
quarter.

$3,661,341based upon a total of 1,760,260 shares held as
of June 30, 2012 by persons believed to be non-affiliates of the Registrant; the basis of the calculation does not constitute a
determination by the Registrant as defined in Rule 405 of the Securities Act of 1933, as amended, that such calculation, if made
as of a date within 60 days of this filing, would yield a different value.

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN
BANKRUPTCY

PROCEEDINGS DURING THE
PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents
and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution
of securities under a plan confirmed by a court. Yes [ ] No [ ]

(APPLICABLE ONLY TO CORPORATE REGISTRANTS)

Indicate the number of shares outstanding of each of the issuer's
classes of common, as of the latest practicable date.

Common Stock, $0.01 par value

6,936,269

(Class)

(Outstanding at April 1 2013)

DOCUMENTS INCORPORATED BY REFERENCE

None

-2-

PART I

Item 1. Description of Business

GENERAL

Spindletop Oil & Gas Co. is an independent oil and gas company
engaged in the exploration, development, production and acquisition of oil and natural gas; the rental of oilfield equipment; and
through one of its subsidiaries, the gathering and marketing of natural gas. The terms the "Company", "We",
"Us" or “Spindletop” are used interchangeably herein to refer to Spindletop Oil & Gas Co. (“SOG”)
and its wholly owned subsidiaries, Spindletop Drilling Company ("SDC"), and Prairie Pipeline Co. (“PPC”).

The Company has focused its oil and gas operations principally in
Texas, although we operate properties in six states including: Texas, Oklahoma, New Mexico, Louisiana, Alabama and Arkansas. We
operate a majority of our projects through the drilling and production phases. Our staff has a great deal of experience in the
operations arena. We have traditionally leveraged the risks associated with drilling by obtaining industry partners to share in
the costs.

In addition, the Company, through PPC, owns approximately 26.1 miles
of pipelines located in Texas, which are used for the gathering of natural gas. These gathering lines are located in the Fort Worth
Basin and are being utilized to transport the Company's natural gas as well as natural gas produced by third parties.

Website Access to Our Reports

We make available free of charge through our website, www.spindletopoil.com,
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K, and all amendments to those reports
as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission. Information
on our website is not a part of this report.

Operating Approach

We believe that a major attribute of the Company is its long history
with, and extensive knowledge of, the Fort Worth Basin of Texas. Our technical staff has an average of over 20 years oil and gas
experience, most of it in the Fort Worth Basin.

One of our strengths has been the ability of the Company to look
at cost effective ways to grow our production. We have traditionally increased our reserve base in one of two ways. Initially,
in the 1970s and 1980s, the Company obtained its production through an exploration and development drilling program focused principally
in the Fort Worth Basin of North Texas. Today, the Company has retained many of these wells as producing properties and holds a
large amount of acreage by production in that Basin.

From the 1990s through 2003, the Company took advantage of the lower
product prices by cost effectively adding to its reserve base through value-priced acquisitions. We found that through selective
purchases we could make producing property acquisitions that were more cost effective than drilling.

During this time period, the Company acquired a large number of operated
and non-operated oil and gas properties in various states.

From 2003 through the fourth quarter of 2008, we returned our focus
to a strategy of development drilling with an emphasis on our Barnett Shale acreage. Since 2009, we split our focus by looking
for value-priced acquisitions combined with development drilling prospects. In the current economic climate, we are continuing
our efforts to acquire producing properties and taking a more conservative approach to development of our leasehold acreage. We
are looking at growth through acquisitions and limited drilling. With current lower natural gas prices and high costs to produce,
we believe that it is prudent to carefully evaluate all our options and make sure that each transaction can be supported in today’s
lower price environment.

-3-

Strategic Business Plans

One of our key strategies is to enhance shareholder value through
implementation of plans for controlled growth and development. The Company's long-term focus is to grow its oil and gas production
through a strategic combination of selected property acquisitions, to the extent feasible, and an exploration and development program
primarily based on developing its leasehold acreage. Additionally, the Company plans to continue to rework existing wells to increase
production and reserves.

The Company's primary area of operation has been in the State of
Texas with an emphasis in the geological province known as the Fort Worth Basin. We plan to continue to focus on operations in
Texas, and we want to capitalize on our strengths which include an extensive knowledge of the various reservoirs in Texas, experience
in operations in this geographic area, development of lease holdings, and utilization of existing infrastructure to minimize costs.

The Company will continue to generate and evaluate prospects using
its own technical staff. The Company intends to fund operations primarily from cash flow generated by operations.

Project Significant Areas

The Company owns various interests in wells located in 15 states
and the Company’s operations are currently located in 6 of those states which include Alabama, Arkansas, Louisiana, Oklahoma,
New Mexico and Texas.

The Company holds approximately 96,925gross acres under lease
in 15 states. The majority of the leases are held by production. A breakout of the Company’s leasehold acreage by geographic
area is as follows:

Operated

Non-Operated

Percent

Properties

Properties

Total

of Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Geographic Area

Acres

Acres

Acres

Acres

Acres

Acres

Acres

Acres

North Texas (1)

7,700

7,184

2,254

236

9,954

7,420

10.27

%

34.14

%

East Texas

2,802

2,342

9,654

744

12,456

3,086

12.85

%

14.20

%

Gulf Coast Texas

3,943

2,345

2,930

223

6,873

2,568

7.09

%

11.82

%

West Texas

1,109

821

2,664

109

3,773

930

3.89

%

4.28

%

Texas Panhandle

680

680

1,360

80

2,040

760

2.10

%

3.50

%

Alabama

1,160

634

2,509

183

3,669

817

3.79

%

3.76

%

Arkansas

2,296

1,960

4,329

116

6,625

2,076

6.84

%

9.55

%

Louisiana

838

551

2,938

138

3,776

689

3.90

%

3.17

%

New Mexico

1,684

997

360

4

2,044

1,001

2.11

%

4.61

%

Oklahoma

317

184

33,405

1,020

33,722

1,204

34.79

%

5.54

%

California

—

892

6

892

6

0.92

%

0.03

%

Colorado

—

1,200

64

1,200

64

1.24

%

0.29

%

Kansas

—

640

184

640

184

0.66

%

0.85

%

Michigan

—

240

6

240

6

0.25

%

0.03

%

Mississippi

—

140

6

140

6

0.14

%

0.03

%

Montana

—

3,090

152

3,090

152

3.19

%

0.70

%

North Dakota

—

1,262

138

1,262

138

1.30

%

0.64

%

Utah

—

2,729

487

2,729

487

2.82

%

2.24

%

Wyoming

—

1,800

134

1,800

134

1.86

%

0.62

%

Total

22,529

17,698

74,396

4,030

96,925

21,728

100.01

%

100.00

%

(1) North Texas includes the Fort Worth Basin & Bend Arch

The majority of the Company’s net acres (67.94%)
are located in Texas.

-4-

A breakout
of the Company's most significant oil and gas reserves by geographic area is as follows:

BOE

North Texas including the Fort Worth Basin & Bend Arch

873,337

55.01

%

East Texas

225,925

14.23

%

Panhandle Texas

73,592

4.64

%

West Texas

72,937

4.59

%

Gulf Coast Texas

35,450

2.23

%

Total Texas

1,281,240

80.71

%

Alabama

97,955

6.17

%

Oklahoma

77,477

4.88

%

New Mexico

65,563

4.13

%

Louisiana

44,213

2.78

%

Montana

15,173

0.96

%

North Dakota

2,008

0.13

%

Kansas

1,815

0.11

%

Wyoming

1,795

0.11

%

Michigan

207

0.01

%

California

107

0.01

%

Total Other States

306,313

19.29

%

Total

1,587,553

100.00

%

North Texas - Fort Worth Basin & Bend
Arch

The Fort Worth Basin-Bend Arch Province has been the focal point
of the Company since its inception. Our technical personnel have an average of 20 years of exploration, drilling, completing, and
production experience extracting natural gas and oil from both conventional and unconventional hydrocarbon deposits found across
the basin. Furthermore, the Company maintains comprehensive and extensive dossiers of geologic and engineering data gathered from
the province. Exploration and development drilling for hydrocarbons across the Fort Worth Basin-Bend Arch Province continue to
remain strong.

The Fort Worth Basin-Bend Arch Province is a major United States
onshore natural gas-prone expanse containing multiple pay zones that range in depth from one thousand to nine thousand (1,000-9,000)
feet. Improved technical advances in fracturing and stimulation technologies, have helped unlock natural gas and oil reserves from
the hydrocarbon bearing Barnett Shale Formation; and thus, continue to bolster vigorous exploration and development activities
that target these conventional and unconventional reservoir reserves throughout the province.

The Barnett Shale is a thick blanket type natural gas bearing stratigraphic
zone found throughout the Fort Worth Basin-Bend Arch Province. The natural gas reserves in place are significant; however, as a
consequence of the extreme low permeability character of the shales, it has been technically challenging to produce these reserves.
According to the United States Geological Survey assessment, an estimated 26.7 trillion cubic feet (TCF) of

undiscovered natural
gas, 98.5 MMBO of undiscovered oil, as well as a mean of 1.1 BBNGL of undiscovered natural gas liquids reserves remain within the
54,000 square mile Fort Worth Basin-Bend Arch Province. More than 98 percent or approximately 26.2 TCF of the undiscovered natural
gas is contained in the organic-rich Mississippian Barnett Shale. Combined, recent advances in hydraulic fracturing, completion
procedures, as well as refined horizontal well drilling technologies continue to enable economic recovery of natural gas reserves
from tight-gas reservoirs throughout the Fort Worth Basin-Bend Arch Province. Undiscovered conventional reservoir natural gas reserves
are estimated to be 467 billion cubic feet of gas (BCFG) the majority of which is dissolved in conventional oil accumulations (source:
United States Geological Survey Energy Resource Program).

-5-

The Company has 9,954gross acres under lease across the prolific
Fort Worth Basin-Bend Arch Province the majority of which, is held by production from the more shallow producing zones. The Company
uses recent and emerging technologies, as well as proven industry practices to develop and produce oil and natural gas from its
properties. Additionally, the Company has a dedicated and well-trained team of employees and professional staff that continually
seek out low-risk profitable drilling and acquisition opportunities throughout the Fort Worth Basin-Bend Arch Province.

Texas Panhandle

During the first quarter of 2012, the Company participated for a
15% non-operated working interest and an 11.25% net revenue interest in the Pope 140 #3H well in Ochiltree County, Texas. The well
was spudded on February 21, 2012, and drilled to a depth of 10,988 ft. The well was completed on April 21, 2012, in the Cleveland
Formation. The well had initial potential flowing (IPF) of 198 bopd, 1,685 mcfgpd, and 357 bswpd on April 24, 2012.

East Texas

The Company has participated in several new horizontal wells drilled
under farmout agreements the Company granted to a third party non-related operator on its leasehold acreage block on its Leona
East Prospect located in the south central portion of Leon County, Texas.

During the fourth quarter of 2011, the Company participated for a
5% non-operated working interest and a 3.75% net revenue interest in the Easterling #1H well in Leon County, Texas. The well was
spudded on January 6, 2012, and drilled to a depth of 13,636 ft. On February 20, 2012, the well was completed in the Woodbine formation.
The well had an initial potential flowing (IPF) of 516 bopd, 1 mcfgpd and 643 bswpd on April 29, 2012.

During the fourth quarter of 2011, the Company participated for a
3.2425% non-operated working interest and a 2.431875% net revenue interest in the Patrick #1H well in Leon County, Texas. This
well was spudded on October 29, 2011, in the Halliday field, and drilled to a depth of 14,872 ft. The well was completed on February
20, 2012, in the Woodbine formation and began producing from a perforated interval from 7,742 ft. to 14,692 ft. during the first
quarter of 2012 at an average rate of 476 bopd, 182 mcfgpd, and 422 bswpd for the first full month.

During the second quarter of 2012, the Company participated for a
14.5833% non-operated working interest and a 10.9375% net revenue interest in the A. M. Easterling-Gresham SA #1H well in Leon
County, Texas. On June 29, 2012, the well was spudded in the Halliday field, and drilled to a depth of 14,274 ft. The well was
cased and completed in the Woodbine formation on August 23, 2012. The operator of the well reported that the well tested on a 32/64th
choke at a rate of 919 bopd and 139 mcfgpd from the Woodbine formation. The well has a 6,730 ft. lateral, was completed with 24
stages of fracturing, and is perforated from 7,452 ft. to 14,140 ft.

During the third quarter of 2012, the Keeling #1H well was spudded
in the Halliday field in Leon County, Texas. The well reached a total depth of 15,985 ft. in the Woodbine formation. The well was
cased to a depth of 14,072 ft. on September 15, 2012, was completed on November 28, 2012, and had an initial potential flowing
(IPF) of 716 bopd and 816 bswpd with a FTP of 410 psi on a 24/64th choke on December 5, 2012.

The Company owns approximately a 17% working interest in the well
with specific interest to be determined upon completion of a division order title opinion for the well. Additional well locations
have been permitted and are currently being permitted in this field by the operator, which the Company will have additional rights
of participation in for yet to be determined amounts and which will vary depending upon the drilling locations for those wells
and the Company’s leasehold positions with respect to those wells. One of the additional wells that as already been drilled
and completed is the Keeling #2H well, on which the operator reported an initial potential test on December 10, 2012, of 504 bopd
and 574 bswpd with a FTP of 450 psi on a 20/64th choke from the Woodbine formation. The company is awaiting further
title information from the operator for a determination of its percentage participation in the Keeling #2H well as well as for
the additional wells being permitted by the operator in this field.

-6-

North Texas

Effective July 1, 2012, the Company acquired operations and a 100%
working interest and an 80.576743% net revenue interest in five natural gas wells in the Newark East Field in Denton County, Texas.
The Wyatt #1 through #5 wells were producing from the Barnett Shale formation at a rate of 40 mcfgpd, 59 mcfgpd, 48 mcfgpd, 62
mcfgpd and 77 mcfgpd, respectively, as of the effective date.

South Texas

During the third quarter of 2011, the Company drilled two wells with
100% working interest and 60.83984% net revenue interest on its Hynes lease in Bee County, Texas. The Hynes #29R and #30R, both
in the Papalote field, were drilled and cased to test the Catahoula Formation at an approximate depth of 3,453 ft. Both wells are
currently shut-in.

West Texas

Effective October 1, 2012, the Company acquired operations and a
26.5% working interest and a 17.7153% net revenue interest in the Le Petit Pois #1 well in the Dewey Lake, South field in Glasscock
County, Texas. The well was producing 59 mcfgpd and no water from a perforated interval at 10,062 ft. to 10,204 ft. in the Strawn
formation as of the effective date.

On November 27, 2012, the Company elected to participate for a 4.68750%
non-operated working interest and a 3.28125% net revenue interest in the drilling of the Miles #28 well in the Fuhrman-Mascho field
in Andrews County, Texas. The well was spudded on November 14, 2012, and reached a total depth of 4,912 ft. on November 18, 2012.
The well was perforated in the San Andres Formation from 4,556 ft. to 4,790 ft., fractured, and had an initial potential flowing
of 54 bopd, 4 mcfgpd, and 42 bswpd on January 7, 2013.

Effective December 1, 2012, the Company elected to participate for
a 4.68750% non-operated working interest and a 3.28125% net revenue interest in the drilling of the Miles #29 well in the Fuhrman-Mascho
field in Andrews County, Texas. Subsequent to the year end, the well was spudded on February 20, 2013, and reached a total depth
of 4,903’ on February 24, 2013. The well was cased and is currently awaiting completion.

Alabama

During the fourth quarter of 2011, the Company elected to participate
in the drilling of the Jones #28-6 well for a 10.2% non-operated working interest and a 7.653675% net revenue interest, in the
Little Cedar Creek field in Conecuh County, Alabama. The well was drilled to a total depth of 11,750 ft. and cased. The well began
producing on January 26, 2012, from a perforated interval at 11,385 ft. to 11,389 ft. in the Smackover Formation, with an initial
rate of 98 bopd, 122 mcfgpd, and no water.

Effective April 11, 2012, the Company participated for a 10.2049%
non-operated working interest and a 7.653675% net revenue interest in the drilling of the Cedar Creek Land and Timber 28-15 #1
well in the Little Cedar Creek field in Conecuh County, Alabama. The well was drilled to a total depth of 11,745 ft. and completed
on July 31, 2012, in the Smackover Formation. On August 24, 2012, the well was flow tested at a rate of 351 bopd and 401 mcfgpd
and no water on an 18/64th choke with FTP of 380 psi.

Effective July 30, 2012, the Company participated for a 10.2049%
non-operated working interest and a 7.653675% net revenue interest in the drilling of the Cedar Creek Land and Timber 27-13 #1
well in the Little Cedar Creek field in Conecuh County, Alabama. The well was drilled to a total depth of 11,800 ft. and was cased
on September 3, 2012. The well was perforated in the Smackover from 11,480-11,490 ft. then acidized with 2,000 gals of 15% FE acid.
The well was placed into production on November 10, 2012, at an initial rate of 86 bopd, 75 mcfgpd and 48 bswpd.

Montana

Effective June 1, 2012, the Company acquired a 7.4031% non-operated
working interest and a 5.9225% net revenue interest in the Hage #44-20 well in the Diamond Point field in Roosevelt County, Montana.
The well was producing approximately 10 bopd and 261 bswpd from a perforated interval of the Red River Formation as of the effective
date.

-7-

Also effective June 1, 2012, the Company acquired a 7.4031% non-operated
working interest and a 5.9225% net revenue interest in the Consolidated State #42-20 well in the Diamond Point field in Roosevelt
County, Montana. The well was producing approximately 22 bopd, 7 mcfgpd, and 408 bswpd from perforated intervals of the Interlake
and Red River formations as of the effective date.

The Company also acquired a 7.4031% non-operated working interest
in the Consolidated State SWD well in Roosevelt County, Montana, in the Diamond Point Field. The well is being utilized to dispose
of produced water from the State #42-20 and the Hage #44-20 wells.

Oklahoma

Effective January 1, 2012, the Company acquired operations and a
22.6875% working interest and a 16.4681% net revenue interest the Weryackwe #1-28 well in the Apache Townsite field in Caddo County,
Oklahoma. The well was producing approximately 42 mcfgpd and 0.4 bswpd from a perforated interval from 4,470 ft. to 4,702 ft. in
the Arbuckle formation as of the effective date.

For all of the above wells, the Company cautions that the initial
production rates of a newly completed well or newly recompleted well or the production rates at the effective date of acquisition
may not be an indicator of stabilized production rates or an indicator of the ultimate recoveries obtained.

Oil and Natural Gas Reserves

The net proved crude oil and gas reserves of the Company as of December
31, 2012 were 498,720 barrels of oil and condensate and 6.533
BCFG of natural gas. Based on SEC guidelines, the reserves were classified as follows:

Barrels of Oil

BCF of Gas

Proved Developed Producing

467,980

6.506

Proved Developed Non-Producing

30,740

0.027

Proved Undeveloped

—

—

Total Proved Reserves

498,720

6.533

Only reserves that fell within the Proved classification were considered.
Other categories such as Probable or Possible Reserves were not considered. No value was given to the potential future development
of behind pipe reserves, untested fault blocks, or the potential for deeper reservoirs (other than Barnett Shale proved undeveloped
reserves directly offset by producing wells which are slated for drilling in the next five years) underlying the Company's properties.
Shut-in uneconomic wells and insignificant non-operated interests were excluded.

The Company has operational control over the majority of these reserves
and can therefore to a large extent control the timing of development and production.

Barrels of Oil Equivalent (BOE)

The Company's Operated Wells

1,279,272

81

%

Non-Operated Wells

308,282

19

%

Total

1,587,553

100

%

Financial Information Relating to Industry Segments

The Company has three identifiable business segments: (1) exploration,
acquisition, development and production of oil and natural gas, (2) gas gathering, and (3) commercial real estate investment. Footnote
15 to the Consolidated Financial Statements filed herein sets forth the relevant information regarding revenues, income from operations
and identifiable assets for these segments.

Narrative Description of Business

The Company is engaged in the exploration, development, acquisition
and production of oil and natural gas, and the gathering and marketing of natural gas. The Company is also engaged in commercial
real estate leasing through leasing office space to non-related third party tenants in the Company’s corporate headquarters
office building.

Principal Products, Distribution and Availability

The principal products marketed by the Company are crude oil and
natural gas which are sold to major oil and gas companies, brokers, pipelines and distributors, and oil and gas properties which
are acquired and sold to oil and gas development entities. Reserves of oil and gas are depleted upon extraction, and the Company
is in competition with other entities for the discovery of new prospects.

The Company is also engaged in the gathering and marketing of natural
gas through its subsidiary PPC, which owns 26.1 miles of pipelines and currently gathers approximately 1,345 mcfgpd. Natural gas
is gathered for a fee. Substantially all of the gas gathered by the Company is gas produced from wells that the Company operates
and in which it owns a working interest.

-9-

The Company owns land and a two story commercial office building
in Dallas, Texas, which it uses as its principal headquarters office. The Company leases the remainder of the building to non-related
third party commercial tenants at prevailing market rates.

Patents, Licenses and Franchises

Oil and gas leases of the Company are obtained from the owner of
the mineral estate. The leases are generally for a primary term of three or more years, and often have extension options for an
equivalent period as the original primary term for payment of additional bonus consideration. The leases customarily provide for
extension beyond their primary term for as long as oil and gas are produced in commercial quantities or other operations are conducted
on such leases as provided by the terms of the leases.

The Company currently holds interests in producing and non-producing
oil and gas leases. The existence of the oil and gas leases and the terms of the oil and gas leases are important to the business
of the Company because future additions to reserves will come from oil and gas leases currently owned by the Company, and others
that may be acquired, when they are proven to be productive. The Company is continuing to purchase oil and gas leases in areas
where it currently has production, and also in other areas.

Dependence on Customers

The following is a summary of significant purchasers / operators
(listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period
ended December 31, 2012:

Purchaser / Operator

2012

2011

2010

Shell Trading (US) Company

15

%

20

%

7

%

Pruet Production Co.

9

%

0

%

0

%

Enbridge Energy Partners

9

%

22

%

26

%

Targa Midstream Service, LIM

8

%

4

%

3

%

Halcon Resources Operating, Inc.

7

%

0

%

0

%

Eastex Crude Company

6

%

7

%

7

%

Crosstex Gulf Coast Mktg

5

%

11

%

16

%

Panther Energy Company, LLC

4

%

0

%

0

%

Gulfmark Energy, Inc.

4

%

3

%

0

%

HollyFrontier Refining & Marketing LLC

3

%

2

%

3

%

Petromax Operating Co., Inc.

3

%

0

%

0

%

Sunoco Partners Marketing

3

%

1

%

1

%

Encana Oil & Gas (USA), Inc.

3

%

0

%

0

%

Enterprise Crude Oil, LLC

2

%

5

%

5

%

Enervest Operating, LLC

2

%

0

%

0

%

Sklar Exploration Co., LLC

2

%

0

%

0

%

ETC Texas Pipeline

2

%

2

%

2

%

Oil and gas is sold to approximately
100 different purchasers under market sensitive, short-term contracts computed on a month to month basis.

Except as set forth above, there are no other customers of the Company
that individually accounted for more than two percent of the Company's oil and gas revenues during the three years ended

December 31, 2012.

The Company currently has no hedged contracts.

-10-

Prospective Drilling Activities

The Company's primary oil and gas prospect generation and acquisition
efforts have been in known producing areas in the United States with emphasis devoted to Texas.

The Company intends to use a portion of its available funds to participate
in drilling activities. The Company does not own any drilling rigs and all drilling activity is performed by independent drilling
contractors. The Company does not refine or otherwise process its oil and gas production.

Exploration for oil and gas is normally conducted with the Company
acquiring undeveloped oil and gas leases under prospects, and carrying out exploratory drilling on the prospective leasehold with
the Company retaining a majority interest in the prospect. Interests in the property are sometimes sold to key employees and associated
companies at cost. Also, interests may be sold to third parties with the Company retaining an overriding royalty interest, carried
working interest, or a reversionary interest.

A prospect is a geographical area designated by the Company for the
purpose of searching for oil and gas reserves and reasonably expected by it to contain at least one oil or gas reservoir. The Company
utilizes its own funds along with the issuance of common stock and options to purchase common stock in some limited cases, to acquire
oil and gas leases covering the lands comprising the prospects. These leases are selected by the Company and are obtained directly
from the landowners, as well as from landmen, geologists, other oil companies, some of whom may be affiliated with the Company,
and by direct purchase, farm-in, or option agreements. After an initial test well is drilled on a property, any subsequent development
drilling of such prospect will normally require the Company to fund the development activities.

Special Tax Provisions

See Footnote 8 to Consolidated Financial Statements regarding the
accounting for income taxes.

Employees

The Company employs or contracts for the services of a total of approximately
sixty-two people. Twenty-seven are full-time employees. The remainder are part-time employees or independent contractors.
We believe that our relationships with our employees are good.

In order to effectively utilize our resources, we employ the services
of independent consultants and contractors to perform a variety of professional and technical services, including in the areas
of lease acquisition, land related documentation and contracts, drilling and completion work, pumping, inspection, testing, maintenance
and specialized services. We believe that it can be more cost effective to utilize the services of consultants and independent
contractors for some of these services.

We depend to a large extent on the services of certain key management
personnel and officers, and the loss of any these individuals could have a material adverse effect on our operations. The Company
does not maintain key-man life insurance policies on its employees.

Financial information about foreign and domestic operations and
export sales

All of the Company's business is conducted domestically, with no
export sales.

Compliance with Environmental Regulations

Our oil and natural gas operations are subject to numerous United
States federal, state and local laws and regulations relating to the protection of the environment, including those governing the
discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and clean-up
of contaminated science. We could incur material costs, including clean-up costs, fines and civil and criminal

-11-

sanctions and third
party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and
regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability
for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were
taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future
environmental laws and regulations which may be more stringent.

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of terms commonly
used in the oil and gas industry that are used in this Report. The terms defined herein may be found in this report in both upper
and lower case or a combination of both.

"BBL" means a barrel of 42 U.S. gallons.

“BBNGL” means billion barrels of natural gas liquids.

“BCF” or “BCFG” means billion cubic feet.

"BOE" means barrels of oil equivalent; converting volumes
of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.

“BOPD” means barrels of oil per day.

"BTU" means British Thermal Units. British Thermal Unit
means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“BSWPD” means barrels of salt water per day.

"Completion" means the installation of permanent equipment
for the production of oil or gas.

"Development Well" means a well drilled within the proved
area of an oil or gas reservoir to the depth of a strata graphic horizon known to be productive.

"Dry Hole" or "Dry Well" means a well found to
be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production
expenses and taxes.

"Exploratory Well" means a well drilled to find and produce
oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.

"Farm-Out" means an agreement pursuant to which the owner
of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to
drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the
acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is
a "farm-in" and the assignor issues a "farm-out."

"Farm-In" see "Farm-Out" above.

"Gas" means natural gas.

"Gross" when used with respect to acres or wells, refers
to the total acres or wells in which we have a working interest.

"Infill Drilling" means drilling of an additional well
or wells provided for by an existing spacing order to more adequately drain a reservoir.

"MCF" or “MCFG” means thousand cubic feet.

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“MCFGPD” means thousand cubic feet of gas per day.

"MCFE" means MCF of natural gas equivalent; converting
volumes of oil to natural gas equivalent volumes using a ratio of one BBL of oil to six MCF of natural gas.

“MMBO” means million barrels of oil.

"MMBTU" means one million BTUs.

"Net" when used with respect to acres or wells, refers
to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

"Net Production" means production that is owned by the
Company less royalties and production due others.

"Non-Operated" or "Outside Operated" means wells
that are operated by a third party.

"Operator" means the individual or company responsible
for the exploration, development, production and management of an oil or gas well or lease.

“Overriding Royalty” means a royalty interest which is
usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

"Present Value" ("PV") when used with respect
to oil and gas reserves, means the estimated future gross revenues to be generated from the production of proved reserves calculated
in accordance with the guidelines of the SEC, net of estimated production and future development costs as of the date of estimation
without future escalation, and discounted using an annual discount rate of 10%. Prices are not escalated and are computed using
a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of
the year (except to the extent a contract specifically provides otherwise). No effect is given to non-property related expenses
such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.

"Productive Wells" or "Producing Wells" consist
of producing wells and wells capable of production, including wells waiting on pipeline connections.

"Proved Developed Reserves" means reserves that can be
expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces
and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project
or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

"Proved Reserves" means the estimated quantities of crude
oil and natural gas which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions.

(i) Reservoirs are considered proved if either
actual production or

conclusive formation tests support economic
producibility. The area of

a reservoir considered proved includes (A) that
portion delineated by

drilling and defined by gas-oil and/or oil-water
contacts, if any; and

(B) the immediately adjoining portions not yet
drilled, but which can

be reasonably judged as economically productive
on the basis of

available geological and engineering data. In
the absence of

information on fluid contacts, the lowest known
structural occurrence

of hydrocarbons controls the lower proved limit
of the reservoir.

-13-

(ii) Reserves which can be produced economically
through application

of improved recovery techniques (such as fluid
injection) are included

in the "proved" classification when
successful testing by a pilot

project, or the operation of an installed program
in the reservoir,

provides support for the engineering analysis
on which the project or

program was based.

(iii) Estimates of proved reserves do not include
the following: (A)

oil that may become available from known reservoirs
but is classified

separately as "indicated additional reserves";
(B) crude oil and

natural gas, the recovery of which is subject
to reasonable doubt

because of uncertainty as to geology, reservoir
characteristics or

economic factors; (C) crude oil and natural
gas that may occur in

undrilled prospects; and (D) crude oil and natural
gas that may be

recovered from oil shales, coal, gilsonite and
other such resources.

"Proved Undeveloped Reserves" means reserves that are recovered
from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves
on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there
is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

"Recompletion" means the completion for production of an
existing well bore in another formation from that in which the well has been previously completed.

"Reserves" means proved reserves.

"Reservoir" means a porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual
and separate from other reservoirs.

"Royalty" means an interest in an oil and gas lease that
gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of
the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells
on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at
the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with
a transfer to a subsequent owner.

“TCF” means trillion cubic feet.

"2-D Seismic" means an advanced technology method by which
a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single
source profile.

"3-D Seismic" means an advanced technology method by which
a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected
over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys
and contribute significantly to field appraisal, development and production.

"Working Interest" means an interest in an oil and gas
lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the
owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner
is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance
of the production accruing to the owners of royalties.

"Workover" means operations on a producing well to restore
or increase production.

-14-

Item 1A.Risk Factors

Risks related directly to our Company

One should carefully consider the following risk factors, in addition
to the other information set forth in this Report, before investing in shares of our common stock. Each of these risk factors could
adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment
in our common stock. Some information in this Report may contain "forward-looking" statements that discuss future expectations
of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual
results to differ materially from those contained in any forward-looking statements.

The current global economic and financial environment could lead
to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce
national and worldwide demand for oil and natural gas and result in lower commodity prices forlong periods of time. Costs
of exploration, development and production have not yet adjusted to current economic conditions. or in proportion to the significant
reduction in product prices. Prolonged,substantial decreases in oil and natural gas prices would likelyhave a material
adverse effect on Spindletop’s business, financial condition and results of operations, could further limit the Company's
access to liquidity and credit and could hinder its ability to satisfy its capital requirements.

Capital and credit markets have experienced unprecedented volatility
and disruption during recent years. Given the current levels of market volatility and disruption, the availability of funds from
those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and
the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest
rates, enacted tighter lending standards or altogether ceased to provide funding to borrowers.

Due to these capital and credit market conditions, Spindletop cannot
be certain that funding will be available to the Company in amounts or on terms acceptable to the Company. The Company is evaluating
whether current cash balances and cash flow from operations alone would be sufficient to provide working capital to fully fund
the Company's operations. Accordingly, the Company is evaluating alternatives, such as joint ventures with third parties, or
sales of interest in one or more of its properties. Such transactions if undertaken, could result in a reduction in the Company's
operating interests or require the Company to relinquish the right to operate the property. There can be no assurance that any
such transactions can be completed or that such transactions will satisfy the Company's operating capital requirements. If the
Company is not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable
to the Company, Spindletop would be required to curtail its expenditures or restructure its operations, and the Company would be
unable to continue its exploration, drilling, and recompletion program, any of which would have a material adverse effect on Spindletop's
business, financial condition and results of operations.

We face significant competition, and many of our competitors
have resources in excess of our available resources.

The oil and gas industry is highly competitive. We encounter competition
from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and sale of
crude oil and natural gas. Our competitors include major integrated oil and gas companies and numerous independent oil and gas
companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially
larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas
properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects
than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future
will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive
environment.

-15-

Exploratory drilling is a speculative activity that
may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

Drilling activities are subject to many risks, including the risk
that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by
us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable
efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return
a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our
drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control,
including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions,
compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. In today's environment,
shortages make drilling rigs, labor and services difficult to obtain and could cause delays or inability to proceed with our drilling
and development plans. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the
movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our
future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial
condition and results of operations.

Our operations are also subject to all the hazards and risks normally
incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual
or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows
of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us
due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage
and suspension of operations. We participate in insurance coverage maintained by the operator of its wells, although there can
be no assurances that such coverage will be sufficient to prevent a material adverse effect to us in such events.

The vast majority of our oil and gas reserves are classified as proved
reserves. Recovery of the Company's future proved undeveloped reserves will require significant capital expenditures. Our management
estimates that aggregate capital expenditures of approximately $ 108,000 will be required to fully develop some of these reserves
in the next twelve month period. No assurance can be given that our estimates of capital expenditures will prove accurate, that
our financing sources will be sufficient to fully fund our planned development activities or that development activities will be
either successful or in accordance with our schedule. Additionally, any significant decrease in oil and gas prices or any significant
increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No
assurance can be given that any wells will produce oil or gas in commercially profitable quantities.

We are subject to uncertainties in reserve estimates and future
net cash flows.

This annual report contains estimates of our oil and gas reserves
and the future net cash flows from those reserves. These estimates have been prepared by Company personnel for 2012, 2011 and 2010.
There are numerous uncertainties inherent in estimating quantities of reserves of oil and gas and in projecting future rates of
production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this
annual report are based on various assumptions, including, for example, constant oil and gas prices, operating expenses, capital
expenditures and the availability of funds, and therefore, are inherently imprecise indications of future net cash flows. Actual
future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves
may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect
the estimated quantity and value of reserves set forth in this prospectus. Additionally, our reserves may be subject to downward
or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and
gas prices and other factors, many of which are beyond our control.

-16-

The present value of future net reserves discounted at 10% (the "PV-10")
of proved reserves referred to in this annual report should not be construed as the current market value of the estimated proved
reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted
future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual
future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing
of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In
addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not
necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with
our reserves or the oil and gas industry in general. Furthermore, our reserves may be subject to downward or upward revision based
upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other
factors. See "Properties - Oil and Gas Reserves."

Unless we replace our oil and natural gas reserves, our reserves
and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration
activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing
oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics
and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly
dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional
recoverable reserves. We may be unable to make such acquisitions because we are:

unable to obtain financing for these acquisitions on economically acceptable
terms; or

·

outbid by competitors.

If we are unable to develop, exploit, find or acquire additional
reserves to replace our current and future production, our cash flow and income will decline as production declines, until our
existing properties would be incapable of sustaining commercial production.

There are risks in acquiring producing oil and gas properties,
including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with
acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations.

One of our business strategies includes growing our reserve base
through acquisitions. Our failure to integrate acquired properties successfully into our existing business, or the expense incurred
in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation
obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may
ultimately be materially greater than estimated at the time of the acquisition.

We are continually investigating opportunities for acquisitions.
In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result
in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise
be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained
by our ability to obtain additional financing.

-17-

Possible future acquisitions could result in our incurring debt,
contingent liabilities and expense, all of which could have a material effect on our financial condition and operating results.

Acquisitions may prove to be worth less than we paid because
of uncertainties in evaluating recoverable reserves and potential liabilities.

Successful acquisitions require an assessment of a number of factors,
including estimates of recoverable reserves, exploration potential, recovery applicability from waterflood and Enhanced Oil Recovery
techniques (“EOR”), future oil and natural gas prices, operating costs and potential environmental and other liabilities.
Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review
of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal
all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties
to fully assess their deficiencies and capabilities. We do not inspect every well or property. Even when we inspect a well or property,
we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled
to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests
in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result
of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or
be able to complete such acquisitions on acceptable terms.

Additionally, significant acquisitions can change the nature of our
operations and business depending upon the character of the acquired properties, which may have substantially different operating
and geological characteristics or be in different geographic locations than our existing properties. It is our current intention
to continue focusing on acquiring properties with development and exploration potential located in onshore United States. To the
extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties
that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently
as in our prior acquisitions.

We cannot control activities on properties we do not operate.
Failure to fund capital expenditure requirements may result in reduction or forfeiture of our interests in some of our non-operated
projects.

We do not operate some of the properties in which we have an interest
and we have limited ability to exercise influence over operations for these properties or their associated costs. As of December
31, 2012, approximately 19% of our crude oil and natural gas proved reserves were operated by other companies. Our dependence on
other operators and other working interest owners for these projects and our limited ability to influence operations and associated
costs could materially adversely affect the realization of our targeted return on capital in drilling or acquisition activities
and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties
operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial
resources, approval of other participants for drilling wells and utilization of technology.

When we are not the majority owner or operator of a particular crude
oil or natural gas project, we may have no control over the timing or amount of capital expenditures associated with such project.
If we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or
operator, our interests in these projects may be reduced or forfeited.

We are subject to risks associated with the current
United States Government Administration’s proposed budget features.

The Obama administration has set forth budget proposals which if
passed, would significantly curtail our ability to attract investors and raise capital. Proposed changes in the Federal income
tax laws which would eliminate or reduce the percentage depletion deduction and the deduction for intangible drilling and development
costs for small independent producers, will significantly reduce the investment capital available to those in the industry as well
as our Company. Lengthening the time to expense seismic costs will also have an adverse effect on our ability to explore and find
new reserves.

-18-

We are subject to various operating and other casualty risks
that could result in liability exposure or the loss of production and revenues.

Our oil and gas business involves a variety of operating risks, including,
but not limited to, unexpected formations or pressures, uncontrollable flows of oil, gas, brine or well fluids into the environment
(including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal
injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are
reasonable, we are not fully insured against all risks. We do not carry business interruption insurance. Losses and liabilities
arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.

From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The curtailments
range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a
few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the
duration of such curtailments. We are not currently experiencing any material curtailment of our production.

We intend to increase to some extentour development and,
to a lesser extent, exploration activities. Exploration drilling and, to a lesser extent, development drilling of oil and gas reserves
involve a high degree of risk that no commercial production will be obtained and/or that production will be insufficient to recover
drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations
may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance
with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not
assure a profit on the investment or a recovery of drilling, completion and operating costs.

We depend on our key management personnel and technical experts
and the loss of any of these individuals could adversely affect our business.

If we lose the services of our key management personnel, technical
experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development
efforts and ability to grow could suffer. We have assembled a team of engineers and geologists who have considerable experience
in applying advanced drilling and completion techniques to explore for and to develop crude oil and natural gas. We depend upon
the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated
with our participation in crude oil and natural gas exploration and development projects. In addition, the success of our business
depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Chris Mazzini, our Chief
Executive Officer, President and Chairman of the Board. We do not have an employment agreement with or key-man life insurance on
Mr. Mazzini or any of our other employees.

Certain of
our affiliates control a majority of our outstanding common stock, which may affect your vote as a shareholder.

Our executive officers, directors and their affiliates hold approximately
85% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such shareholders have
the ability to exert significant influence over our business affairs, including the ability to control the election of directors
and results of voting on all matters requiring shareholder approval. This concentration of voting power may delay or prevent a
potential change in control.

-19-

Certain of our affiliates have engaged in business transactions
with the Company, which may result in conflicts of interest.

Certain officers, directors and related parties, including entities
controlled by Mr. Mazzini, the President and Chief Executive Officer, have engaged in business transactions with the Company which
were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions
were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future
transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties
and will be approved by a majority of the disinterested members of our Board of Directors.

Our common stock is traded on the Over-the-Counter market and
is currently quoted on the OTC Bulletin Board (“OTCQB”), symbol "SPND".

The liquidity of our common stock may be adversely affected, and
purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade in
that or another suitable trading market.

There is presently only a limited public market for our common stock,
and there is no assurance that a ready public market for our securities will develop. It is likely that any market that develops
for our common stock will be highly volatile and that the trading volume in such market will be limited. The trading price of our
common stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements
of our drilling results and other events or factors. In addition, the United States stock market has from time to time experienced
extreme price and volume fluctuations that have affected the market price for many companies and which often have been unrelated
to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities.

We do not intend to declare dividends in the foreseeable future.

Our Board of Directors presently intends to retain all of our earnings
for the expansion of our business. We therefore do not anticipate the distribution of cash dividends in the foreseeable future.
Any future decision of our Board of Directors to pay cash dividends will depend, among other factors, upon our earnings, financial
position and cash requirements.

We are subject to certain title risks.

Our company employees and contract land professionals have reviewed
title records or other title review materials relating to substantially all of our producing properties. The title investigation
performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling,
consistent with industry standards. We believe we have satisfactory title to all our producing properties in accordance with standards
generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating
agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the
value of such properties. At December 31, 2012, our leaseholds for some of our net acreage were being kept in force by virtue of
production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and
requires production in paying quantities prior to expiration of various time periods to avoid lease termination.

-20-

We expect to make acquisitions of oil and gas properties from
time to time subject to available resources. In making an acquisition, we generally focus most of our title and valuation efforts
on the more significant properties. It is generally not feasible for us to review in-depth every property we purchase and all
records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal
existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies
and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection
process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which
may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties,
obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing
or financially able to give contractual protection against such problems, and we may decide to assume environmental and other
liabilities in connection with acquired properties.

Our business is highly capital-intensive requiring continuous development
and acquisition of oil and gas reserves. In addition, capital is required to operate and expand our oil and gas field operations
and purchase equipment. At December 31, 2012, we had working capital of $5,939,000. We anticipate that we will be able to meet
our cash requirements for the next 12 months. However, if such plans or assumptions change or prove to be inaccurate, we could
be required to seek additional financing sooner than currently anticipated.

We have funded our operations, acquisitions and expansion costs primarily
through our internally generated cash flow. Our success in obtaining the necessary capital resources to fund future costs associated
with our operations and expansion plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery
of our proved producing and proved developed non-producing oil and gas reserves; and (ii) maintain effective cost controls at the
corporate administrative office and in field operations. However, even if we achieve some success with our plans, there can be
no assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or fund our expansion
plans.

We have substantial capital requirements necessary for undeveloped
properties for which we may not be able to obtain adequate financing.

Development of our properties will require additional capital resources.
We have no commitments to obtain any additional debt or equity financing and there can be no assurance that additional financing
will be available, when required, on favorable terms to us. The inability to obtain additional financing could have a material
adverse effect on us, including requiring us to curtail significantly our oil and gas acquisition and development plans or farm-out
development of our properties. Any additional financing may involve substantial dilution to the interests of our shareholders at
that time.

Oil and natural gas prices fluctuate widely and low prices
could have a material adverse impact on our business and financial results.

Our revenues, profitability and the carrying value of our oil and
gas properties are substantially dependent upon prevailing prices of, and demand for, oil and gas and the costs of acquiring, finding,
developing and producing reserves. Our ability to obtain borrowing capacity, to repay future indebtedness, and to obtain additional
capital on favorable terms is also substantially dependent upon oil and gas prices. Historically, the markets for oil and gas have
been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations
in response to: (i) relatively minor changes in the supply of, and demand for, oil and gas; (ii) market uncertainty; and (iii)
a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions,
the price and availability of domestic and imported oil and gas, the level of consumer and industrial demand, weather, domestic
and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore,
the marketability of our production depends in part

-21-

upon the availability, proximity and capacity of gathering systems, pipelines
and processing facilities. Volatility in oil and gas prices could affect our ability to market our production through such systems,
pipelines or facilities. As of December 31, 2012, approximately 87% of our oil and gas production is currently sold to 17 purchasing
firms on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic
forces during 2012, 2011, and 2010, and experienced fluctuations similar to those seen in natural gas prices for the year. We believe
that oil prices will continue to fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries
("OPEC"), changes in demand from many Asian countries, current events in the Middle East, security threats to the United
States, and other factors associated with the world political and economic environment. As a result of the many uncertainties associated
with levels of production maintained by OPEC and other oil producing countries, the availabilities of worldwide energy supplies
and competitive relationships and consumer perceptions of various energy sources, we are unable to predict what changes will occur
in crude oil and natural gas prices.

We may be responsible for additional costs in connection with
abandonment of properties.

We are responsible for payment of plugging and abandonment costs
on its oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that in most cases, the
ultimate aggregate salvage value of lease and well equipment located on our properties should equal to the costs of abandoning
such properties. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with
the abandonment of any of our properties. In addition, abandonment costs and their timing may change due to many factors, including
actual production results, inflation rates and changes in environmental laws and regulations.

Risks that Involve the Oil & Gas Industry in General.

We are subject to various governmental regulations which may
cause us to incur substantial costs.

Our operations are affected from time to time in varying degrees
by political developments and federal, state and local laws and regulations. In particular, oil and gas production related operations
are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure
to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all
applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict
the future cost or impact of complying with such laws and regulations.

Sales of natural gas by us are not regulated and are generally made
at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation
rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us
for sales of such production. Sales of our natural gas currently are made at uncontrolled market prices, subject to applicable
contract provisions and price fluctuations that normally attend sales of commodity products.

Since the mid-1980s, the FERC has issued a series of orders, culminating
in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of
natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including
the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services
such pipelines previously performed. One of the FERC's purposes in issuing the orders was to increase competition within all phases
of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have
been the subject of appeals, and the courts have largely upheld Order 636. Because further review of certain of these orders is
still possible, and other appeals may be pending, it is difficult to exactly predict the ultimate impact of the orders on us and
our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional
role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.

-22-

While significant regulatory uncertainty remains, Order 636 may ultimately
enhance our ability to market and transport our natural gas, although it may also subject us to greater competition, more restrictive
pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order
636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued
a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1997, the
FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service rate making
methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any
additional FERC action on these matters would affect us only indirectly, these policy statements and proposed rule changes are
intended to further enhance competition in natural gas markets. We cannot predict what the FERC will take on these matters, nor
can we predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However,
we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.

The price we receive from the sale of oil is affected by the cost
of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system
for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions
and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent
adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are not able to predict
with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation
costs or reduce wellhead prices for oil.

The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and
production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions
for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation
of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil
and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes
and regulations than any other similarly situated oil and gas company.

We may not have enough insurance to cover all of the risks
we face, which could result in significant financial exposure.

We maintain insurance coverage against some, but not all, potential
losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost
of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance,
it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution
and environmental risks.

-23-

We are subject to various environmental risks which may cause
us to incur substantial costs.

Our operations and properties are subject to extensive and changing
federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling
and transportation of oil and gas and the discharge of materials into the environment, and relating to safety and health. The recent
trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences
and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness
and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required
for our various operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities
have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In
the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we
have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes
in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us. The impact
of such changes, however, would not likely be any more burdensome to us than to any other similarly situated oil and gas company.

The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose liability, without regard
to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal
site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found
at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and
several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for
damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the environment.

We generate typical oil and gas field wastes, including hazardous
wastes that are subject to the Federal Resources Conservation and Recovery Act and comparable state statutes. The United States
Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous
and non-hazardous wastes. Furthermore, certain wastes generated by our oil and gas operations that are currently exempt from regulation
as "hazardous wastes" may in the future be designated as "hazardous wastes", and therefore be subject to more
rigorous and costly operating and disposal requirements.

The Oil Pollution Act ("OPA") imposes a variety of requirements
on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and
liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the
owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement
for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs
and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA.
OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in
a spill event may subject a responsible party to civil or criminal enforcement actions.

We own or lease properties that for many years have produced oil
and gas. We also own natural gas gathering systems. It is not uncommon for such properties to be contaminated with hydrocarbons.
Although we or previous owners of these interests may have used operating and disposal practices that were standard in the industry
at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties or on or under other
locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that
could require us to remove any such wastes or to remediate the resulting contamination. In addition to properties that we operate,
we have interests in many properties which are operated by third parties over whom we have limited control. Notwithstanding our
lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental
regulations may, in certain circumstances, adversely impact us.

Item 1B. Unresolved Staff Comments

None

-24-

Item 2. Properties

OIL AND GAS PROPERTIES

The following table sets forth pertinent data with respect to the
Company-owned oil and gas properties, all located within the continental United States, as estimated by the Company:

Years Ended December 31,

2012

2011

2010

Gas and Oil Properties, net (1)

Proved developed gas reserves-Mcf (2)

Proved developed producing

6,506,000

8,124,000

8,106,000

Proved developed non-producing

27,000

27,000

648,000

Proved undeveloped gas reserves-Mcf (3)

—

—

1,868,000

Total proved gas reserves-Mcf

6,533,000

8,151,000

10,622,000

Proved Developed Crude Oil and

Condensate reserves-Bbls (2)

Proved developed producing

468,000

401,000

328,000

Proved developed non-producing

31,000

31,000

34,000

Proved Undeveloped crude oil and

Condensate reserves-Bbls (3)

—

—

—

499,000

432,000

362,000

(1) The estimate of the net proved oil and gas reserves, future
net revenues, and the present value of future net revenues.

(2) "Proved Developed Oil and Gas Reserves" are reserves
that can be expected to be recovered through existing wells with existing equipment and operating methods.

(3) "Proved Undeveloped Reserves" are reserves that are
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required
for recompletion. See Footnote 18 to the Financial Statements, Supplemental Reserve Information (Unaudited), for further explanation
of the changes for 2010 through 2012.

(4) Reserve amounts are rounded to the nearest thousand.

Productive Wells

The following table sets forth our domestic productive wells and
includes both operated wells and wells operated by third parties at December 31, 2012.

Gas Wells

Oil Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

356

98.56

173

64.14

529

162.70

-25-

Acreage

The following table sets forth our undeveloped and developed gross
and net leasehold acreage for our operated and non-operated wells at December 31, 2012. Undeveloped acreage includes leased acres
on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and
gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage should not be confused with undrilled
acreage held by Production under the terms of a lease. Undrilled acreage held by production under the terms of a lease is included
in the Developed Acreage category total shown below.

UndevelopedAcreage

DevelopedAcreage

Total Acreage

Gross

Net

Gross

Net

Gross

Net

4,960

1,554

96,925

21,728

101,885

23,282

All the leases for the undeveloped acreage summarized in the
preceding table will expire at the end of their respective primary terms unless prior to that date, the existing leases are renewed
or production has been obtained from the acreage subject to the lease, in which event the lease will remain in effect until the
cessation of production. As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title
except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition
in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will
not result from title defect or from defects in the assignment of leasehold rights.

Wells Drilled and Completed

The Company's working interests in both operated and outside operated
exploration and development wells completed during the years indicated were as follows:

2012

2011

2010

Gross

Net

Gross

Net

Gross

Net

Exploratory Wells (1):

Productive

—

—

—

—

—

—

Non-Productive

—

—

—

—

—

—

Total

—

—

—

—

—

—

Developed Wells (2):

Productive

9.000

1.321

11.000

1.036

10.000

1.391

Non-Productive

—

—

—

—

—

—

Total

9.000

1.321

11.000

1.036

10.000

1.391

Total Exploration & Development Wells:

Productive

9.000

1.321

11.000

1.036

10.000

1.391

Non-Productive

—

—

—

—

—

—

Total

9.000

1.321

11.000

1.036

10.000

1.391

-26-

(1) An exploratory well is a well drilled to find and produce oil
or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir,
or to extend a known reservoir.

(2) A development well is a well drilled within the proved area of
an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

The following tables set forth additional data with respect to production
from Company-owned oil and gas operated and non-operated properties, all located within the continental United States:

For the years ended December 31,

2012

2011

2010

2009

2008

Oil and Gas Production, net:

Natural Gas (Mcf)

791,708

733,816

823,957

866,416

1,231,835

Crude Oil & Condensate (Bbl)

79,514

48,708

31,526

25,875

32,663

Average Sales Price per Unit Produced

Natural Gas (Mcf)

$

3.64

$

5.34

$

4.89

$

4.13

$

8.41

Crude Oil & Condensate (Bbl)

$

89.50

$

83.85

$

74.35

$

56.55

$

71.21

Average Production Cost per Equivalent Barrel (1) (2)

$

16.65

$

19.02

$

15.48

$

14.37

$

14.98

(1) Includes severance taxes and ad valorem taxes.

(2) Gas production is converted to equivalent barrels at the rate
of six MCFG per barrel, representing relative energy content of natural gas to oil.

The Company owns producing royalties and overriding royalties under
properties located in Texas. The revenue from these properties is not significant.

The Company is not aware of any major discovery or other favorable
or adverse event that is believed to have caused a significant change in the estimated proved reserves since December 31, 2011.

OFFICE SPACE

The Company owns a commercial office building. The property is a
two story multi-tenant, garden office building with a sub-grade parking garage. The 31 year old building contains approximately
46,286 rentable square feet and sits on a 1.4919 acre block of land situated in north Dallas, Texas in close proximity to hotels,
restaurants and shopping areas (the Galleria Mall) with easy access to Interstate Highway 635 (LBJ Freeway) and Dallas Parkway
(North Dallas Toll Road). The Company occupies approximately 12,759 rentable square feet of the building as its primary office
headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market
rates.

The address of the Company's principal executive offices is One Spindletop
Centre, 12850 Spurling Road, Suite 200, Dallas, Texas 75230. The telephone number is (972) 644-2581.

-27-

PIPELINES

The Company owns, through its subsidiary, PPC, 26.1 miles of natural
gas pipelines in Parker, Palo Pinto and Eastland Counties, Texas. These pipelines are steel and polyethylene and range in size
from two inches to four inches. These pipelines primarily gather natural gas from wells operated by the Company and in which the
Company owns a working interest, but also for other parties.

The Company normally does not purchase and resell natural gas, but
gathers gas for a fee. The fees charged in some cases are subject to regulations by the State of Texas and the Federal Energy Regulatory
Commission. Average daily volumes of gas gathered by the pipelines owned by the Company were 1,345, 1,604, and 1,793, mcfgpd for
2012, 2011, and 2010, respectively.

Oilfield Production Equipment

The Company owns various natural gas compressors, pumping units,
dehydrators and various other pieces of oil field production equipment.

Substantially all of the equipment is located on oil and gas properties
operated by the Company and in which it owns a working interest. The rental fees are charged as lease operating fees to each property
and each owner.

M-R Oilfield Services, LP, is an oilfield service company which provides
roustabout, swabbing and completion services to the Company at rates which are at or below market. This limited partnership has
Chris G. Mazzini and Michelle H. Mazzini as its limited partners. This oilfield services company currently does work exclusively
for the Company and its related company, Giant Energy, although it has contemplated doing work for unrelated third parties as well.
The Company benefits by having immediate access to services.

Item 3. Legal Proceedings

Neither the Registrant nor its subsidiaries nor any officers or directors
is a party to any material pending legal proceedings for or against the Company or its subsidiary nor are any of their properties
subject to any proceedings.

During the fourth quarter of the fiscal year covered by this report,
no proceeding previously reported was terminated.

The Company's common stock trades over-the-counter under the symbol
"SPND".

Prior to 2004, no significant public trading market had been established
for the Company's common stock. The Company does not believe that listings of bid and asking prices for its stock are indicative
of the actual trades of its stock, since trades are made infrequently. The following table shows high and low trading prices for
each quarter in 2012, 2011, and 2010.

-28-

Price Per Share

High

Low

2012

First Quarter

$1.90

$1.50

Second Quarter

2.35

1.84

Third Quarter

2.09

1.91

Fourth Quarter

3.10

1.86

2011

First Quarter

2.79

2.79

Second Quarter

2.52

1.52

Third Quarter

2.00

1.70

Fourth Quarter

2.10

1.70

2010

First Quarter

1.99

1.65

Second Quarter

5.50

1.60

Third Quarter

2.25

1.39

Fourth Quarter

2.25

1.45

During the First Quarter of 2013, subsequent to year end, the following high and low prices were recorded for the Company's common stock

Price Per Share

High

Low

2013

First Quarter

$2.60

$2.08

There is no amount of common stock that is subject to outstanding
warrants to purchase, or securities convertible into, common stock of the Company.

According to the transfer records of the Company at April 1, 2013,
common stock of the Company was held by approximately 545 known holders of record.

The following chart compares the yearly percentage change in the
cumulative total stockholder return on the Company's Common Stock during the five years ended December 31, 2012 with the cumulative
total return of the Standard and Poor's 500 Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow
Jones Secondary Oil Stock Index). The comparison assumes $100 was invested on December 31, 2007 in the Company's Common Stock and
in each of the foregoing indices and assumes reinvestment of dividends. The Company paid no dividends on its Common Stock during
the five-year period.

-29-

Stock Performance Chart

Comparison of Five-Year Cumulative Total Return
Among

Spindletop Oil & Gas Co., S&P 500
Index and

the Dow Jones U.S. Exploration and Production
Index

The Company has not paid any dividends since its reorganization and
it is not contemplated that it will pay any dividends on its Common Stock in the foreseeable future. The Business Loan Agreement
entered into between the Company and JPMorgan Chase Bank for the purpose of acquiring its commercial office building contains restrictions
on the payment of dividends in the event a default under terms of the Business Loan Agreement has occurred and is continuing or
would result from the payment of such dividends or distributions.

The Registrant currently serves as its own stock transfer agent and
registrar.

The Company has not approved nor authorized any standing repurchase
program for its common stock.

During the fourth quarter of the fiscal year ended December 31, 2012,
the Company made the following repurchases of its common stock:

Effective October 30, 2012, the Company repurchased 700,000
shares of its common stock for a purchase price of $1,491,000 or $2.13 per share.

On December 18, 2012, the Company repurchased 24,534 shares
of its common stock for a purchase price of $36,801 or $1.50 per share.

The repurchased shares are held as Treasury Stock.

-30-

Item 6. Selected Financial Data

The selected financial information presented should be read in conjunction
with the consolidated financial statements and the related notes thereto.

For the years ended December 31,

2012

2011

2010

2009

2008

Total Revenue

$

12,106,000

$

9,340,000

$

7,656,000

$

6,913,000

$

14,064,000

Net Income

3,659,000

1,753,000

447,000

39,000

3,521,000

Earnings per Share

$

0.49

$

0.23

$

0.06

$

0.01

$

0.46

For the years ended December 31,

2012

2011

2010

2009

2008

Total Assets

$

24,653,000

$

23,279,000

$

20,777,000

$

20,386,000

$

21,289,000

Long-Term Debt

600,000

720,000

840,000

960,000

1,080,000

Item 7. Management's Discussion And Analysis
Of Financial Condition And

Results Of Operations

Liquidity and Capital Resources

The Company's operating capital needs, as well as its capital spending
program are generally funded from cash flow generated by operations. Because future cash flow is subject to a number of variables,
such as the level of production and the sales price of oil and natural gas, the Company can provide no assurance that its operations
will provide cash sufficient to maintain current levels of capital spending. Accordingly, the Company may be required to seek additional
financing from third parties in order to fund its exploration and development programs.

Results of Operations

2012 Compared to 2011

Oil revenue for 2012 was approximately $7,116,000 compared to $4,084,000
for 2011, an increase of approximately $3,032,000 or 74%. Oil prices increased to an average of $89.49 per barrel in 2012 from
an average of $83.85 per bbl in 2011, an increase of $5.63 per bbl or 7%. In addition to the increase in prices, oil sales increased
to 79,514 bbls from approximately 48,708 bbls in 2011, an increase of 30,814 bbls or 63%. The increase in oil revenue and sales
is predominantly due to participation in new wells during the last half 2012.

Gas revenue for 2012 was approximately $2,882,000 compared to $3,916,000
for 2011, a decrease of approximately $1,034,000 or 26%. Gas sales increased to approximately 792,000 mcf in 2012 from approximately
734,000 mcf in 2011, an increase of 58,000 mcf or 8%. The net increase in natural gas sales was due to the participation in, and
the acquisition of new wells. Gas prices, however, decreased to an average of $3.64 per mcf in 2012, a decrease of $1.70 or 32%
from an average of $5.34 per mcf in 2011.

-31-

Revenue from lease operations was $359,000 for 2012, an increase
of $70,000 or 24% from $289,000 in 2011. This was due primarily to an increase in field supervision charges on operated wells of
approximately $44,000 as a result of workover activity during 2012. In addition there was an increase in administrative overhead
billed to working interest owners of approximately $26,000 due primarily to an increase in COPAS overhead rates billed

Revenue from gas gathering for 2012 was $145,000, a decrease of $27,000
or 16% from $172,000 in 2011. This was due primarily to a decrease in natural gas volume sold through Prairie Pipeline.

Real estate income for 2012 was $242,000, down 44% or $194,000 from
$436,000 in 2011. This was due primarily to the expiration of a large lease contract in late 2011 which was not renewed and some
lease renewal incentives.

Interest income for 2012 was approximately $78,000, a decrease of
approximately $5,000 from approximately $83,000 in 2011 or 6%. Overall interest rates on deposit accounts at most of the banks
in which the Company is a depositor, have decreased over prior years.

Other income for 2012 was $1,284,000, as compared to $360,000 in
2011, an increase of $924,000 or 257%. This change is due to the increase in cash received for farm-out agreements in 2012 over
that received during 2011. From time to time, the Company farms out some of its leasehold acreage to non-affiliated third parties
for exploration and development drilling. Generally, the Company receives a one-time payment for the agreement. The revenues from
these farm-out agreements vary in size and frequency and should not be considered as regularly recurring revenues that the Company
receives.

Lease operations expense for 2012 was $2,631,000 as compared to $2,444,000
in 2011, a net increase of approximately $187,000, or 8%. Of this net increase, approximately $112,000 is due to increased workover
activity, approximately $78,000 is due to new properties added since 2011, and a reduction of approximately $31,000 is due to a
decrease in expenses from non-operated properties. The remaining $28,000 represents net increases and decreases on various properties
due to general price increases and changes in levels of workover activity. These increases were offset by a one-time payment covering
expenses from 2002 to 2011 associated with the acquisition of the working interest in the Davis Heirs #1 well during the first
quarter of 2011.

Production
taxes, gathering, transportation and marketing expenses for 2012 were approximately $891,000 compared to $809,000 in 2011, a net
increase of $82,000. This 10% net increase is the result of an increase in severance taxes based on the increase in oil revenues.
This increase was offset by an overall decrease in severance taxes based on decreased gas revenues and severance tax exemptions
on certain of the Company’s gas wells. Gathering and transportation charges increased due to a net increase in gas volumes
sold during the period, which was offset by an overall decrease in marketing and other deductions.

Pipeline and rental operation expenses were
approximately $26,000 in 2012 compared to approximately $25,000 in 2011, an increase of approximately $1,000 or 4%. This was due
mainly to an increase in the costs associated with compressor and pipeline repairs.

Real estate operations expenses for 2012
were $185,000, down from $225,000 in 2011. This 18% decrease of $40,000 was primarily due to operating efficiencies, from the reduced
usage of the building as the result of the expiration of the lease noted above.

Depreciation and amortization expense for
2012 was $1,647,000 compared to $1,152,000 for 2011, an increase of $495,000, or 43%. The Company re-evaluated its proved oil and
gas reserves as of December 31, 2012, and decreased its estimated total proved reserves by approximately 203,000 BOE to 1,588,000
BOE at the end of 2012 compared to 1,791,000 BOE at the end of 2011, a decrease of approximately 11%. Sales of oil and gas products
during 2012 increased by approximately 40,000 BOE from approximately 171,000 BOE in 2011 to approximately 211,000 BOE in 2012,
an increase of approximately 23%. (See Footnote 18 to the Financial Statements). This resulted in an increase in the depletion
rate factor from 8.718% in 2011 on an unamortized full cost pool base of $11,843,000 to a depletion rate factor of 11.754% on an
unamortized full cost pool base of $13,464,000 in 2012. The net increase in the unamortized full cost pool base of $1,621,000 was
due primarily to an increase in the amounts capitalized in the full cost pool of approximately $2,654,000 less the increase in
accumulated depletion of $1,032,479.

-32-

Asset Retirement Obligation (“ARO”)
accretion expense for 2012 was $40,000 up from $34,000 in 2011; an increase of $6,000 or 17%. The ARO calculation is based on the
Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated obligation
to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on the estimated
life of each property. Changes are incorporated as applicable into the full cost pool and the carrying value of the liability.
Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

General
and administrative expenses for 2012 were $3,719,000 compared to $3,275,000 for 2011, an increase of approximately $444,000 between
years or 14%. This increase is due mainly to payroll and associated employee benefit costs during 2012.

Interest
expense for 2012 was $29,000, down from $55,000 in 2011; a decrease of $26,000 or 47%. The reason for the reduction is the decreasing
loan balance on which interest is paid, and that the interest rate on the loan was adjusted from 6.11% in December, 2011 to 3.61%
for future years.

2011 Compared to 2010

Oil revenue for 2011 was approximately $4,084,000 compared to $2,368,000
for 2010, an increase of approximately $1,716,000 or 72%. Oil prices increased to an average of $83.85 per barrel in 2011 from
an average of $74.35 per bbl in 2010, an increase of $9.50 per bbl or 13%. In addition to the increase in prices, oil sales increased
to 48,708 bbls from approximately 31,526 bbls in 2010, an increase of 17,182 bbls or 55%. The increase in oil revenue and sales
is predominantly due to properties acquired or drilled in 2011.

Gas revenue for 2011 was approximately $3,916,000 compared to $3,934,000
for 2010, a decrease of approximately $18,000 or 0.5%. Gas sales decreased to approximately 734,000 mcf in 2011 from approximately
824,000 mcf in 2010, a reduction of 90,000 mcf or 11%. Gas prices, however, increased to an average of $5.34 per mcf in 2011, an
increase of $0.45 or 9% from an average of $4.89 per mcf in 2010.

Revenue from lease operations was $289,000 for 2011, a decrease of
$30,000 or 9% from $319,000 in 2010. This decrease was a result of lower pumper fees and field supervision costs charged to operated
properties between the two years.

Revenue from gas gathering for 2011 was $172,000, a decrease of $7,000
or 4% from $179,000 in 2010. This was due primarily to the decrease in gas volume sold.

Real estate income for 2011 was $436,000, down 3% or $12,000 from
$448,000 in 2010. This was due primarily to the expiration of a rental contract in late 2011 which was not renewed and some lease
renewal incentives.

Interest income for 2011 was $83,000, a decrease of $75,000 from
$158,000 in 2010 or 47%. Overall interest rates on deposit accounts at most of the banks in which the Company is a depositor, have
decreased significantly over prior years.

Other income for 2011 was $360,000, as compared to $250,000 in 2010,
an increase of $110,000 or 44%. The increase is due primarily to increases in farmouts and assignment of certain leases between
years. In addition, amounts were brought into income from reconciliation efforts on accounts payable for non-operated properties.
Amounts carried as payables were determined not to be liabilities and were taken to income.

Lease
operating expenses increased to $2,444,000 in 2011 from $1,901,000 in 2010 an increase of $543,000 or 29%. Approximately $525,000
of this net increase comes from operated wells drilled or acquired in 2011 or late 2010. Another $185,000 comes from an increase
in non-operated wells, the majority of which is due to the acquisition of a non-operated working interest in the Davis Heirs #1
which included expenses from a time period of 2002 to 2011. Expenses to plug non-economical wells decreased by $157,000 from 2010
and the remaining difference was the result of a net difference in workover costs between the two years.

-33-

Production
taxes, gathering, transportation and marketing expenses for 2011 were approximately $809,000 compared to $712,000 in 2010, a net
increase of $97,000. This 14% net increase is due an increase of approximately $116,000 in Severance Taxes paid on properties acquired
in 2011 or late 2010. This amount is offset by a reduction in other revenue deductions of approximately $20,000.

Pipeline and rental operation expenses were
$25,000 in 2011 from $33,000 in 2010 a decrease of $8,000 or 24%. This was due mainly to a decrease in the costs associated with
compressor and pipeline repairs.

Real estate operations expenses for 2011
were $225,000, down from $246,000 in 2010. This 9% decrease of $21,000 was mainly due to the reduction of electricity costs after
the Company changed electric carriers.

Depreciation and amortization expense for
2011 was $1,152,000 compared to $1,042,000 for 2010, an increase of $110,000, or 11%. The Company re-evaluated its proved oil and
gas reserves as of December 31, 2011, and decreased its estimated total proved reserves by approximately 342,000 BOE to 1,791,000
BOE at the end of 2011 compared to 2,133,000 BOE at the end of 2010, a decrease of approximately 16.0%. Sales of oil and gas products
during 2011 increased by approximately 2,000 BOE from approximately 169,000 BOE in 2010 to approximately 171,000 BOE in 2011, an
increase of approximately 1.2%. (See Footnote 18 to the Financial Statements). This resulted in an increase in the depletion rate
factor from 7.336% in 2010 on an unamortized full cost pot base of $12,496,000 to a depletion rate factor of 8.718% on an unamortized
full cost pot base of $11,843,000 in 2011. The decrease in the unamortized full cost pot base of $653,000 was due primarily to
a reduction of future development costs as calculated in the Company’s reserve report between 2010 and 2011 of approximately
$2,079,000.

Asset Retirement Obligation (“ARO”)
accretion expense for 2011 was $34,000 down from $48,000 in 2010; a decrease of $14,000 or 29%. The ARO calculation is based on
the Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated
obligation to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on
the estimated life of each property. Changes are incorporated as applicable into the full cost pot and the carrying value of the
liability. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

General
and administrative expenses for 2011 were $3,275,000 compared to $3,467,000 for 2010, a decrease of approximately $192,000 between
years or 6%. This decrease is due mainly to the reduction in payroll and associated employee benefit costs during 2011.

Interest
expense for 2011 was $55,000, down from $84,000 in 2010; a decrease of $29,000 or 35%. The majority of this change is due to a
Revenue Agent’s Report assessed in late 2010 that was not incurred in 2011.

Certain Factors That Could Affect Future Operations

Certain information contained in this report, as well as written
and oral statements made or incorporated by reference from time to time by the Company and its representatives in other reports,
filings with the Securities and Exchange Commission, press releases, conferences, teleconferences or otherwise, may be deemed to
be 'forward-looking statements' within the meaning of Section 21E of the Securities Exchange Act of 1934 and are subject to the
'Safe Harbor' provisions of that section.

Forward-looking statements include statements concerning the Company's
and management's plans, objectives, goals, strategies and future operations and performance and the assumptions underlying such
forward-looking statements. When used in this document, the words "anticipates", "estimates", "expects",
"believes", "intends", "plans", and similar expressions are intended to identify such forward-looking
statements. Actual results and developments could differ materially from those expressed in or implied by such statements due to
these and other factor.

-34-

Item 8. Consolidated Financial Statements
and

Schedules Index at Page
46

Item 9. Changes In And Disagreements With
Accountants On Accounting And Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management,
including our Principal Executive Officer and Principal Financial and Accounting Officer, we conducted an evaluation of the effectiveness
of our disclosure controls and procedures (as defined in Rule 13a-15(e)) of the Securities Exchange Act of 1934, as amended (the
“Exchange Act”), which are designed to ensure that information required to be disclosed by us in the reports that we
file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the
SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated
and communicated to our management, including our Principal Executive Officer and Principal Financial and Accounting Officer, as
appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Principal Executive Officer
and Principal Financial and Accounting Officer concluded that our disclosure controls and procedures were effective as of the end
of the period covered by this report.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate
internal control over financial reporting for the Company. Our internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance
with generally accepted accounting principles. There are inherent limitations to the effectiveness of any system of internal control
over financial reporting. These limitations include the possibility of human error, the circumvention of overriding of the system
and reasonable resource constraints. Because of its inherent limitations, our internal control over financial reporting may not
prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may
deteriorate.

Management assessed the effectiveness of the Company’s internal
controls over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth in
Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on management’s assessments and those criteria, management has concluded that Company’s internal control over
financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of the
Company’s registered public accounting firm regarding internal control over financial report. Management’s report was
not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange
Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

In preparation for management’s report on internal control
over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial
reporting. There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule
13a-15(f)) that occurred during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.

-35-

Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors and Executive Officers
Of The Registrant

The Directors and Executive Officers of the Company and certain information concerning them is set forth below:

Name

Age

Position

Chris G. Mazzini

55

Chairman of the Board, Director and President

Michelle H. Mazzini

51

Director, Vice President, Secretary, Treasurer

Ted R. Munselle

57

Director

On January 2, 2012, Mr. David E. Allard, resigned as a member of
the Board of Directors of Spindletop Oil & Gas Co.

On February 17, 2012, Mr. Ted R. Munselle was appointed as a member
of the Board of Directors ofSpindletop Oil & Gas Co. Mr. Munselle is determined to have
all the credentials and qualifications to be an Independent Financial Expert and has been appointed as an Independent Financial
Expert for the Audit Committee of the Board of Directors and has been appointed as Chairman of the Audit Committee.

Except as set forth above, all directors hold offices until the next
annual meeting of the shareholders or until their successors are duly elected and qualified. Officers of the Company serve at the
discretion of the Board of Directors.

Business Experience

Chris Mazzini, Chairman of the Board of Directors and President,
graduated from the University of Texas at Arlington in 1979 with a Bachelor of Science degree in Geology. He started his career
in the oil and gas industry in 1978, and began as a Petroleum Geologist with Spindletop in 1979, working the Fort Worth Basin of
North Texas. He became Vice President of Geology at Spindletop in 1982 and served in that capacity until he left the Company in
1985 when he founded Giant Energy Corp. ("Giant"). Mr. Mazzini has served as President of Giant since then. He rejoined
the Company in December 1999 when he, through Giant, purchased controlling interest. Mr. Mazzini has been Chairman of the Board
of Directors and President of the Company since 1999 and is a Certified and Licensed Petroleum Geologist. Mr. Mazzini has worked
numerous geological basins throughout the United States with an emphasis on the Fort Worth Basin. He is responsible for several
new field discoveries in the Fort Worth Basin.

Michelle Mazzini, Vice President and General Counsel, received her
Bachelor of Science Degree in Business Administration (Major: Accounting) from the University of Southwestern Louisiana (now named
University of Louisiana at Lafayette) where she graduated magna cum laude in 1985. She earned her law degree from Louisiana State
University where she graduated Order of the Coif in 1988. Ms. Mazzini began her career with Thompson & Knight, a large law
firm in Dallas, where she focused her practice on general corporate and finance transactions. She also worked as Corporate Counsel
for Alcatel USA, a global telecommunications manufacturing corporation where her practice was broad-based. Ms. Mazzini serves as
Vice President and General Counsel of the Company.

-36-

On February 17, 2012, Mr. Ted R. Munselle
was appointed as a member of the Board of Directors ofSpindletop
Oil & Gas Co. Mr. Munselle is Vice President and Chief Financial Officer (since October 1998) of Landmark Nurseries, Inc.
He is a Certified Public Accountant (since 1980) who was employed as an Audit Partner in two Dallas, Texas based CPA firms (1986
to 1998), as an Audit Manager at Grant Thornton, LLP (1983 to 1986) and as Audit Staff to Audit Supervisor at Laventhol &
Horwath (1977 to 1983). Mr. Munselle is also a director (since February 2004) of American Realty Investors, Inc. and Transcontinental
Realty Investors, Inc., both of which are Nevada corporations which have their common stock listed and traded on the New York Stock
Exchange (“NYSE”), as well as a director (since May 2009) of Income Opportunity Realty Investors, Inc., a Nevada corporation
which has its common stock listed and traded on the NYSE MKT.

Key and Technical Employees

In addition to the services provided by Mr. Mazzini and Ms. Mazzini
(both of whom have biographies listed above), the Company also relies extensively on the key and the technical employees identified
below.

Michael G. Boos, Geologist, earned a Bachelor of Science degree in
Geology from the University of Delaware in 1979. After performing geophysical research for the State of Delaware seeking hydrothermal
energy sources, Mr. Boos worked independently for many years as a Petroleum Exploration Consultant and as a Staff Explorationist
for a local oil company. He has numerous field discoveries in the Mid-Continent to his credit. In 1993 Mr. Boos joined Spindletop’s
Geological Department. He pursued a Masters degree through the University of Texas system, and later worked as a Geologist and
Senior Project Manager for several national environmental consulting firms until rejoining Spindletop in October, 2008. His petroleum
exploration experience includes Alaska’s North Slope (Prudhoe Bay), many of the continental U.S. producing basins, as well
as Central and South America. He has testified as an expert witness before the Texas Railroad Commission (TRRC) on several occasions.
He is a founding member of both the Geological Information Library of Dallas (GILD, now Geomap) and the American Association of
Petroleum Geologists (AAPG) Environmental Division, and is a licensed Professional Geologist (P.G.) in the states of Texas and
Tennessee.

Dave Chivvis, Petroleum Engineer, joined the Company in May, 2008.
Mr. Chivvis earned his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1993. After graduation,
he worked for Cox Resources Corporation, an independent oil and gas company located in Dallas, Texas. Mr. Chivvis worked in various
engineering areas from operations to acquisitions of oil and gas properties in Texas, Oklahoma, Louisiana, and Arkansas. He then
moved to Los Angeles in 2001 to pursue other opportunities before moving back to Texas to join the Company.

Robert E. Corbin, Controller, has been a full-time employee of Spindletop
since April 2002. From May 2001 until April 2002, Mr. Corbin was an Independent Accounting Consultant and devoted substantially
all of his time to Spindletop. He has been active in the oil and gas industry for over 37 years, during which time he has served
as financial officer of a publicly-held company as well as several private oil and gas companies and partnerships. Mr. Corbin graduated
from Texas Tech University in 1969 with a BBA degree in Accounting and began his accounting career as an auditor with Arthur Andersen
& Co. in 1970. Mr. Corbin is a Certified Public Accountant.

Charles (Chuck) D. Howell, Jr., Geologist, joined the Company in
April, 2008. Mr. Howell earned a Bachelor of Science in Geology from Southern Methodist University in 1999. Currently, he is finishing
his Ph.D. in Geology at the University of Texas at Dallas. Mr. Howell has been in the energy industry since 2003. He began his
career at Pioneer Natural Resources working in the Gulf of Mexico. During 2005, Mr. Howell was an Independent Consulting Geologist
for Anadarko Petroleum Corporation and worked on development of the historic Salt Creek Oil Field. In 2007, immediately before
joining Spindletop Oil and Gas Company, he was a Geologist for Chevron Energy Technology Company in Houston, Texas and was part
of a team of stratigraphic specialists for the West Coast of Africa. Mr. Howell is a long-standing and active member of the American
Association of Petroleum Geologists, the Society for Sedimentary Geology, the Geological Society of America, the International
Association of Sedimentologists, and remains associated with the Ichnology Research Group.

-37-

Dick A. Mastin, Petroleum Landman, has been a full-time employee
of the Company since February, 2006. Mr. Mastin graduated cum laude from Stephen F. Austin State University in 1980 with a Bachelor
of Science in Forestry and a minor in General Business. From September of 1980 until December of 1985, Mr. Mastin worked for Spindletop
Oil & Gas Co. as a Petroleum Landman. He received his Masters of Science in Management and Administrative Sciences from the
University of Texas at Dallas in 1990. In January of 1987, he took a position with the Dallas office of the Federal Bureau of
Investigation. After a year with the Bureau, he accepted a position with the Internal Revenue Service as a Revenue Agent. Fifteen
of his eighteen years with the Service were spent in the Large and Mid-Sized Business unit auditing tax returns of the largest
business entities.

Glenn E. Sparks is the Land Director and also acts as Associate General
Counsel to the Company. Mr. Sparks was previously employed as a Landman by the Company from 1982 through 1986, prior to attending
law school. Mr. Sparks holds a B.B.A. with a concentration in Finance from the University of Texas at Arlington, and a J.D. from
Texas Tech University School of Law. From 1990 to 2005, Mr. Sparks practiced law in a private practice focusing primarily on oil
and gas law and real estate, as a partner in the law firm of Logan & Sparks, PLLC, and has acted as outside legal counsel for
the Company in numerous oil and gas transactions during his years in private practice. Mr. Sparks left his private law practice
and joined the Company again as an employee in his current position in 2005. Mr. Sparks is Board Certified in Oil & Gas Mineral
Law by the Texas Board of Legal Specialization.

Family Relationships

Michelle Mazzini, Vice President, Secretary and General Counsel is
the wife of Chris Mazzini, Chairman of the Board and President.

Involvement in Certain Legal Proceedings

None of the directors or executive officers of the Registrant, during
the past five years, has been involved in any civil or criminal legal proceedings, bankruptcy filings or has been the subject of
an order, judgment or decree of any Federal or State authority involving Federal or State securities laws.

Board Meetings and Committees

The Board of Directors met two times in 2012. The Board has established
an audit committee. The Board is small and all members of the Board serve on the audit committee. The function of the audit committee
is to assist the Board in fulfilling its oversight responsibilities by reviewing the financial information that will be provided
to the shareholders and others, the systems of internal controls that management and the Board of Directors have established, and
the audit process. During 2011, the audit committee was comprised of Mr. David Allard (Chairman), Mr. Chris Mazzini, and Ms. Michelle
Mazzini. Subsequent to December 31, 2011, Mr. Allard resigned as a member of the Board of Directors and as Chairman of the Audit
Committee. Effective with his appointment as a member of the Board of Directors of the Company on February 17, 2012, Mr. Munselle
assumed the position of Chairman of the Audit Committee.

With respect to nominations to the Board, compensation, financial
planning, strategies, and business alternatives, the Company does not have separate committees as the Board is small and all members
of the Board participate in making recommendations and decisions on these matters.

-38-

Item 11. Executive Compensation

Cash Compensation

Cash compensation including salaries and bonuses, of $415,132, $295,686,
and $297,038 was paid to Mr. Mazzini in 2012, 2011, and 2010 respectively. Cash compensation including salaries and bonuses of
$281,950, $168,694, and $170,180 was paid to Ms. Mazzini in 2012, 2011, and 2010 respectively.

The Company has no stock option or incentive plan, does not grant
any plan-based awards or awards of equity securities. The Company has no pension plan for its employees.

Compensation Pursuant to Plan

None

Other Compensation

Key employees and officers of the Company may sometimes be assigned
overriding royalty interests and/or carried working interests in prospects acquired by or generated by the Company. These interests
normally vary from less than one percent to three percent for each employee or officer. There is no set formula or policy for such
program, and the frequency and amounts are largely controlled by the economics of each particular prospect. We believe that these
types of compensation arrangements enable us to attract, retain and provide additional incentives to qualified and experienced
personnel.

Effective August 1, 2011, the Company issued 10,000 shares of restricted
common stock (5,000 shares to each of two individuals) pursuant to an employment package. The shares were valued at $1.70 per share,
the believed market value for free trading shares at the time of issue. The amount was expensed as general and administrative expense.
The shares of common stock were issued out of Treasury Stock and reduced the amount of the Company's common stock held in Treasury
from 36,668 to 26,668 shares.

Effective December 30, 2011, the Company issued 10,000 shares of
restricted common stock to a key employee pursuant to an employment package. The shares were valued at $1.70 per share, the believed
market value for free trading shares at the time of issue. The amount was expensed as general and administrative expense. The shares
of common stock were issued out of Treasury Stock and reduced the amount of the Company's common stock held in Treasury from 26,668
to 16,668 shares.

Compensation of Directors

Directors who are employees
of the Company are not currently compensated for their services on the Board. Mr. Munselle was paid a director’s fee
of $10,000 in 2012 to compensate him for his position as the Board of Directors’ Financial Expert. Mr. Munselle also received
$2,500 for each Board of Directors’ meeting during the year other than the annual meeting. Mr. Munselle was paid a total
of $12,500 in 2012. Mr. Allard was paid a director’s fee of $10,000 in 2011 and $12,500 in 2010.

Termination of Employment and Change of Control
Arrangement

There are no plans or arrangements for payment to officers or directors
upon resignation or a change in control of the Registrant.

The table below sets forth the information indicated regarding ownership
of the Registrant's common stock, $.01 par value, the only outstanding voting securities, as of April 1, 2013 with respect to:
(i) any person who is known to the Registrant to be the owner of more than five percent of the Registrant's common stock; (ii)
the common stock of the Registrant beneficially owned by each of the directors of the Registrant, and (iii) by all officers and
directors as a group. Each person has sole investment and voting power with respect to the shares indicated, except as otherwise
set forth in the footnotes to the table.

Name and Addressof Beneficial Owner

Numberof Shares

Nature ofBeneficialOwnership *

Pct Based onOutstandingPercent ofClass **

Chris Mazzini and Michelle Mazzini

5,900,543

(1)

85.1%

12850 Spurling Rd., Suite 200

Dallas, Texas 75230

All officers and directors as a group

5,900,543

85.1%

* “Beneficial Ownership” means the sole or shared power
to vote, or direct the voting of, a security or investment power with respect to a security, or any combination thereof.

** Percentages are base upon 6,936,269 shares of Common Stock outstanding
at April 1, 2013.

The Company is not aware of any arrangements or pledges with respect
to its securities that may result in a change in control of the Company.

-40-

Item 13. Certain Relationships And Related
Transactions

Transactions with management and others

Certain officers, directors and related parties, including entities
controlled by Mr. Mazzini, the President and Chief Executive Officer, have engaged in business transactions with the Company which
were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions
were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future
transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties
and will be approved by a majority of the disinterested members of our Board of Directors.

Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership
in which they are limited partners, own M-R Oilfield Services, LP ("MRO"), an oilfield service company which provides
roustabout, swabbing and completion services at rates which are at or below market to the Company. This oilfield services company
currently does work exclusively for the Company, its parent company, Giant Energy Corp. and Giant NRG, LP, although MRO is contemplating
offering its services to unrelated third-parties. The Company benefits by having immediate access to services.

Certain Business Relationships

The long-term debt, which is secured by the commercial office building,
is also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related parties.

On October 1, 2008, Giant entered into an Administrative Services
Agreement with the Company whereby Giant pays the Company $250 per month for the Company providing administrative services to Giant.

The Company has entered into a management services agreement with
MRO whereby MRO makes monthly payments in the amount of $1,000 per month to the Company in exchange for the Company providing administrative
services to MRO. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”) a limited
partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500
to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar
arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange
for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP,
a limited partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described
elsewhere in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”) a limited liability
company that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV
pays the Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The
Company entered into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds
some royalty interests owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee
in the amount of $350 for certain administrative services that the Company provides to Reserve. See also note 6 to the Financial
Statements.

-41-

Item 14. Principal Accounting Fees and Services

The following table sets forth the aggregate fees for professional
services rendered to Spindletop Oil & Gas Co. and Subsidiaries for the years 2012, 2011 and 2010 by accounting firm, Farmer,
Fuqua, & Huff, P.C.

Type of Fees

2012

2011

2010

Audit Fees

$

43,000

$

43,000

$

41,000

Audit Related Fees

—

—

—

Tax Fees

—

—

4,000

All other fees

—

—

—

Members of the Board of Directors (the "Board") fulfill
the responsibilities of an audit committee and have established policies and Procedures for the approval and pre-approval of audit
services and permitted non-audit services. The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff,
P.C. independent auditors, to pre-approve their performance of audit services and permitted non-audit services, to approve all
audit and non-audit fees, and to set guidelines for permitted non-audit services and fees. All the fees for 2012, 2011 and 2010
were pre-approved by the Board or were within the pre-approved guidelines for permitted non-audit services and fees established
by the Board, and there were no instances of waiver of approved requirements or guidelines during the same periods.

-42-

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a.

The following documents are filed as a part of this report:

(1) FINANCIAL STATEMENTS: The following financial statements of the Registrant and Report of Independent Registered Public Accounting Firm therein are filed as part of this Report on Form 10-K:

Other financial statement schedules have been omitted because the information required to be set forth therein is not applicable, is immaterial or is shown in the consolidated financial statements or notes thereto.

-43-

(3) EXHIBITS: The following documents are filed as exhibits (or are incorporated by reference as indicated) into Report:

ExhibitDesignation

Exhibit Description

3.1

Articles of Incorporation of Spindletop Oil & Gas Co. (previously filed with our General Form for Registration of Securities on Form 10, filed with the Commission on August 14, 1990)

3.2

Bylaws of Spindletop Oil & Gas Co. (previously filed with our General Form for Registration of Securities on Form 10, filed with the Commission on August 14, 1990)

14

Code of Ethics for Senior Financial Officers (Incorporated by reference to Exhibit 14 to the registrant's annual report Form 10-K for the fiscal year ended December 31, 2005)

21

Subsidiaries of the Registrant

31.1 *

Rule 13a-14(a) Certification of Chief Executive Officer

31.2 *

Rule 13a-14(a) Certification of Chief Financial Officer

32. *

Officers' Section 1350 Certifications

* Filed herewith

(b) The Index of Exhibits is included following the Financial Statement
Schedules beginning at page 71 of this Report.

(c) The Index to Consolidated Financial Statements and Supplemental
Schedules is included following the signatures, beginning at page 46of this Report

-44-

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be been signed in its behalf by the undersigned, thereunto duly authorized.

SPINDLETOP OIL & GAS CO.

Date: April 15, 2013

By:/s/ Chris G. Mazzini

Chris G. Mazzini

President, Principal Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following on behalf of the Registrant and in the capacities and on the dates indicated.

Signatures

Principal Executive Officers

Capacity

Date

/s/ Chris Mazzini

President, Director

April 15, 2013

Chris Mazzini

(Chief Executive Officer

/s/ Michelle Mazzini

Vice President, Secretary,

April 15, 2013

Michelle Mazzini

Treasurer, Director

/s/ Ted R. Munselle

Director

April 15, 2013

Ted R. Munselle

/s/ Robert E. Corbin

Controller (Principal Financial

April 15, 2013

and Accounting Officer)

Robert E. Corbin

-45-

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

Index to Consolidated Financial Statements and Schedules

Page

Report of Independent Registered Public Accounting Firm

47

Consolidated
Balance Sheets - December 31, 2012 and 2011

48-49

Consolidated Statements of Operations for the years ended

December
31, 2012, 2011 and 2010

50

Consolidated Statements of Changes in Shareholders'

Equity
for the years ended December 31, 2012, 2011, and 2010.

51

Consolidated Statements of Cash Flows for the years ended

December 31, 2012, 2011 and 2010

52

Notes
to Consolidated Financial Statements

53

Schedules for the years ended December 31, 2012, 2011 and 2010

II
- Valuation and Qualifying Accounts

71

III - Real Estate and Accumulated Depreciation

72

All other schedules have been omitted because they are not applicable, not required, or the information has been supplied in the consolidated financial statements or notes thereto.

-46-

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM

To the Board of Directors and

Shareholders of Spindletop Oil & Gas Co.

We have audited the accompanying consolidated
balance sheets of Spindletop Oil & Gas Co. (A Texas Corporation) and subsidiaries as of December 31, 2012 and 2011, and the
related consolidated statements of operations, shareholders' equity and cash flows for each of the years in the three-year period
ended December 31, 2012. Spindletop Oil & Gas Co.’s management is responsible for these consolidated financial statements.
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. Our
audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate
in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.

In our opinion, the consolidated financial statements
referred to above present fairly, in all material respects, the financial position of Spindletop Oil & Gas Co. and subsidiaries
as of December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States
of America.

We were not engaged to examine management’s
assertion about the effectiveness of Spindletop Oil & Gas Co.’s internal control over financial reporting as of December
31, 2012 included in the accompanying management report on internal control over financial reporting and, accordingly, we do not
express an opinion thereon.

Our audits were made for the purpose of forming
an opinion on the basic consolidated financial statements taken as a whole. The schedules listed in the index of the consolidated
financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part
of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits
of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the financial data
required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.

Issuance of 10,000 shares of Common Stock out of Treasury Stock as part of an employee compensation package

18,000

(10,000

)

5,000

Net Income (Loss)

$

447,000

Balance December 31,2010

7,677,471

$

77,000

$

919,000

36,668

$

(18,000

)

$

12,603,000

Issuance of 10,000 shares of Common Stock out of Treasury Stock as part of an employee compensation package

12,000

(10,000

)

5,000

Issuance of 10,000 shares of Common Stock out of Treasury Stock as part of an employee compensation package

12,000

(10,000

)

5,000

Net Income (Loss)

$

1,753,000

Balance December 31,2011

7,677,471

$

77,000

$

943,000

16,668

$

(8,000

)

$

14,356,000

Purchase of 700,000 shares of Common Stock as Treasury Stock

700,000

(1,491,000

)

Purchase of 24,534 shares of Common Stock as Treasury Stock

24,534

(37,000

)

Net Income (Loss)

$

3,659,000

Balance December 31,2012

7,677,471

$

77,000

$

943,000

741,202

$

(1,536,000

)

$

18,015,000

The accompanying notes are an integral part of these statements.

-51-

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Twelve Months Ended December 31,

2012

2011

2010

Cash Flows from Operating Activities

Net Income

$

3,659,000

$

1,753,000

$

447,000

Reconciliation of net income to net cash

provided by operating activities

Depreciation and amortization

1,647,000

1,152,000

1,042,000

Accretion of asset retirement obligation

40,000

34,000

48,000

Non-cash employee compensation paid with treasury stock

—

34,000

23,000

Changes in accounts receivable

(546,000

)

(521,000

)

(215,000

)

Changes in prepaid income tax

405,000

41,000

—

Changes in accounts payable

229,000

946,000

(719,000

)

Changes in current tax payable

99,000

—

136,000

Changes in deferred tax payable

(968,000

)

(203,000

)

668,000

Other

9,000

(12,000

)

—

Net cash provided by operating activities

4,574,000

3,224,000

1,430,000

Cash Flows from Investing Activities

Capitalized acquisition, exploration and development costs

(2,464,000

)

(2,453,000

)

(2,760,000

)

Purchase of other property and equipment

(6,000

)

—

(59,000

)

Purchase of other short-term investments

—

—

(400,000

)

Purchase of other long-term investments

—

(200,000

)

(1,000,000

)

Net cash used by investing activities

(2,470,000

)

(2,653,000

)

(4,219,000

)

Cash Flows from Financing Activities

Repayment of note payable to bank

(120,000

)

(120,000

)

(120,000

)

Purchase of 724,534 shares of treasury stock

(1,528,000

)

—

—

Net cash used by financing activities

(1,648,000

)

(120,000

)

(120,000

)

Increase (decrease) in cash

456,000

451,000

(2,909,000

)

Cash at beginning of period

6,695,000

6,244,000

9,153,000

Cash at end of period

$

7,151,000

$

6,695,000

$

6,244,000

The accompanying notes are an integral part of these statements.

-52-

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND ORGANIZATION

Merger and Basis of Presentation

On July 13, 1990, Prairie States Energy Co., a Texas corporation,
(the Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired Company). The name of Prairie States Energy
Co. was changed to Spindletop Oil & Gas Co., a Texas corporation at the time of the merger.

Organization and Nature of Operations

The Company was organized as a Texas corporation in September 1985,
in connection with the Plan of Reorganization ("the Plan"), effective September 9, 1985, of Prairie States Exploration,
Inc., ("Exploration"), a Colorado corporation, which had previously filed for Chapter 11 bankruptcy. In connection with
the Plan, Exploration was merged into the Company, with the Company being the surviving corporation. After giving effect to a stock
split, up to a total of 166,667 of the Company's common shares may be issued to Exploration's former shareholders. As of December
31, 2011, 122,436 shares have been issued to former shareholders in connection with the Plan.

Spindletop Oil & Gas Co. is engaged in the exploration, development
and production of oil and natural gas; and through one of its subsidiaries, the gathering and marketing of natural gas.

The Company owns land along with a commercial office building which
contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet
as its corporate office headquarters. The Company leases the remaining space in the building to non-related third party commercial
tenants at prevailing market rates.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies consistently applied
in the preparation of the accompanying financial statements follows:

FASB Accounting Standards Codification

The Company presents its financial statements in accordance with
generally accepted accounting principles in the United States ("GAAP"). In June, 2009, the Financial Accounting Standards
Board ("FASB") completed its accounting guidance codification project. The FASB Accounting Standards Codification ("ASC")
became effective for the Company's financial statements issued subsequent to June 30, 2009 and is the single source of authoritative
accounting principles recognized by the FASB to be applied to nongovernmental entities in the preparation of financial statements
in conformity with GAAP. Accordingly, the Company refers to the ASC as the sole source of authoritative literature.

Consolidation

The consolidated financial statements include the accounts of Spindletop
Oil & Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and Spindletop Drilling Company. All significant inter-company
transactions and accounts have been eliminated.

-53-

Cash and Cash Equivalents

The Company considers all highly liquid instruments with a maturity
of three months or less to be cash equivalents.

Other Investments

Other short-term and long-term investments consist of certificates
of deposit with maturities of more than three months. Carrying amounts approximate fair value. Amounts for Changes in other short-term
investments and Changes in other long-term investments in the Consolidated Statements of Cash Flows for 2010 have been reclassified
to conform with the classifications shown in the 2011 Consolidated Statements of Cash Flows.

Allowance for Doubtful Accounts

The Company provides an allowance for doubtful accounts equal to
the estimated uncollectible portion of accounts receivable. This estimate is based on historical collection experience and a review
of the current status of accounts receivable.

Oil and Gas Properties

The Company follows the full cost method of accounting for its oil
and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are
capitalized and accounted for in cost centers, on a country-by-country basis. For each cost center, capitalized costs, less accumulated
amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of:

a)The present value of estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements)
to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated
future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount
factor of ten percent and assuming continuation of existing economic conditions; plus

b)The cost of properties not being amortized; plus

c)The lower of cost or estimated fair market value of unproven properties
included in the costs being amortized; less

d)Income tax effects related to differences between the book and tax
basis of the properties.

If unamortized costs capitalized within a cost center, less related
deferred income taxes, exceed the cost center ceiling (as defined), the excess is charged to expense and separately disclosed during
the period in which the excess occurs. Amounts required to be written off will not be reinstated for any subsequent increase in
the cost center ceiling. No impairment of oil and gas properties charge was recorded for 2012, 2011 or 2010.

Depreciation and amortization for each cost center are computed on
a composite unit-of-production method, based on estimated proven reserves attributable to the respective cost center. All costs
associated with oil and gas properties are currently included in the base for computation and amortization. Such costs include
all acquisition, exploration, development costs and estimated future expenditures for proved undeveloped properties as well as
estimated dismantlement and abandonment costs as calculated under the asset retirement obligation category, net of salvage value.
All of the Company's oil and gas properties are located within the continental United States.

Gains and losses on sales of oil and gas properties are treated as
adjustments of capitalized costs. Gains or losses on sales of property and equipment, other than oil and gas properties, are recognized
as part of operations. Expenditures for renewals and improvements are capitalized, while expenditures for maintenance and repairs
are charged to operations as incurred.

-54-

Property and Equipment

The Company, as operator, leases equipment to owners of oil and gas
wells, on a month-to-month basis.

The Company, as operator, transports gas through its gas gathering
systems, in exchange for a fee.

Depreciation is provided in amounts sufficient to relate the cost
of depreciable assets to operations over their estimated service lives (5 to 10 years for rental equipment and gas gathering systems,
4 to 5 years for other property and equipment). The straight-line method of depreciation is used for financial reporting purposes,
while accelerated methods are used for tax purposes.

Real Estate Property

The Company owns land along with a two-story commercial office building
which is situated thereon. The Company occupies a portion of the building as its primary corporate headquarters, and leases the
remaining space in the building to non-related third party commercial tenants at prevailing market rates. The Company depreciates
the commercial office using the straight-line method of depreciation for financial statement and income tax purposes.

Investments in Real Estate

All investments in real estate holdings are stated at cost or adjusted
carrying value. ASC Topic 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that a property
be considered impaired if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the
carrying amount of the property. If impairment exists, an impairment loss is recognized by a charge against earnings equal to the
amount by which the carrying amount of the property exceeds fair market value less cost to sell the property. If impairment of
a property is recognized, the carrying amount of the property is reduced by the amount of the impairment, and a new cost for the
property is established. Depreciation is provided over the properties estimated remaining useful life. There was no charge to earnings
during 2012 due to impairment of real estate holdings.

Accounting for Asset Retirement Obligations

The Company adopted ASC Topic 410-20, "Accounting for Asset
Retirement Obligations" on December 31, 2005. This statement requires the recording of a liability in the period in which
an asset retirement obligation ("ARO") is incurred, in an amount equal to the discounted estimated fair value of the
obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The determination
of the ARO is based on an estimate of the future cost to plug and abandon our oil and gas wells. The actual costs could be higher
or lower than current estimates.

The following table reflects the changes of the asset retirement
obligations during the period ending December 31;

2012

2011

Carrying amount of asset retirement obligation

$

946,000

$

854,000

Liabilities added

55,000

42,000

Liabilities divested or settled

(92,000

)

16,000

Current period accretion expenses

40,000

34,000

Carrying amount as of December 31,

$

949,000

$

946,000

-55-

Revenue Recognition

The Company follows the “sales” (takes or cash) method
of accounting for oil and gas revenues. Under this method, the Company recognizes revenues on oil and gas production as it is taken
and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on
our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural
gas imbalances are insignificant.

Income Taxes

In June, 2006, an interpretation of ASC Topic 740-10, “Accounting
for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty
in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also
provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition
of certain tax positions. Federal and state tax authorities generally have the right to examine and audit the previous three years
of tax returns filed.

The Company adopted the provisions of the interpretation of ASC Topic
740-10 effective January 1, 2007. The adoption of this accounting principle did not have an effect on the Company’s consolidated
financial statements at, and for the three years ended December 31, 2012.

The Company accounts for income taxes pursuant to ASC Topic 740-10
"Accounting for Income Taxes" , which requires the recognition of deferred tax liabilities and assets for the expected
future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Under this method,
deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and
tax bases of assets and liabilities, using enacted tax rates in effect in the years in which the differences are expected to reverse.
The temporary differences primarily relate to depreciation, depletion and intangible drilling costs.

Use of Estimates

The preparation of financial statements in conformity with U. S.
Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Share-Based Payments

Effective January 1, 2006, the Company adopted ASC Topic 718-10,
“Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized
in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant-date
fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and
for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing
accounting practices or the amount of share-based compensation recognized in earnings.

Recently Issued Accounting Pronouncements

Currently, there are no new accounting pronouncements that were issued
to be effective in 2012 or subsequent thereto that would have a material impact on the Company’s financial reporting.

-56-

Subsequent Events

The Company has evaluated subsequent events through the
issuance date of April 15, 2013.

3.ACCOUNTS RECEIVABLE

December 31,

2012

2011

Trade

$

21,000

$

101,000

Accrued receivable

2,149,000

1,523,000

2,170,000

1,624,000

Less: Allowance for losses

(15,000

)

(15,000

)

$

2,155,000

$

1,609,000

Accrued receivables are receivables from purchasers of oil and gas.
These revenues are booked from check stub detail after receipt of the check for sales of oil and gas products. These payments are
for sales of oil and gas produced in the reporting period, but for which payment has not yet been received until after the closing
date of the reporting period. Therefore these sales are accrued as receivables as of the balance sheet date. Revenues for oil and
gas production that has been sold but for which payment has not yet been received is accrued in the period sold.

4. ACCOUNTS PAYABLE

December 31,

2012

2011

Trade payables

$

1,101,000

$

1,170,000

Production proceeds payable

2,189,000

1,865,000

Prepaid drilling costs

161,000

187,000

$

3,451,000

$

3,222,000

-57-

5.NOTES PAYABLE

December 31,

2012

2011

Note payable to a bank with monthly principal payments of $10,000 plus accrued interest at a variable annual interest rate based upon an index which is the Treasury securities rate for a term of seven years, plus 2.2%. The interest rate is subject to change on the first day of each seven year anniversary after the date of the rate based on the Index than in effect. As of the date of the loan, the annual interest rate was 6.11%. Effective December 27, 2011, the annual interest rate was adjusted to 3.61%. The note is collateralized by land and a commercial office building, plus a guarantee by certain related parties. The note matures in November, 2018.

720,000

840,000

Less current maturities

(120,000)

(120,000)

Total notes payable, long-term portion

600,000

720,000

Estimated annual maturities for long-term debt are as follows:

2013

120,000

2014

120,000

2015

120,000

2016

120,000

2017

120,000

thereafter

120,000

720,000

6. RELATED PARTY TRANSACTIONS

On October 1, 2008, Giant entered into an Administrative Services
Agreement with the Company whereby Giant agreed to pay the Company $250 per month for the Company providing administrative services
to Giant. The Company also entered into a management services agreement with M-R Oilfield Services, LP (“MRO”), whereby
MRO makes monthly payments in the amount of $1,000 to the Company in exchange for the Company providing administrative services
to MRO. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”), a limited partnership
with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the Company
in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar arrangement
with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange for the
Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited
partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described elsewhere
in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”), a limited liability company
that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV pays the
Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The Company entered
into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds some royalty interests
owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee in the amount of $350 for
certain administrative services that the Company provides to Reserve.

The long-term debt, which is secured by the commercial office building,
is also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related parties.

-58-

7. COMMON STOCK

Effective January 1, 2006, the Company adopted ASC Topic 718-10,
"Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized
in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant
date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption
and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing
accounting practices or the amount of share-based compensation recognized in earnings.

Effective December 1, 2010, the Company issued 10,000 shares of restricted
common stock to a key employee pursuant to an employment package. The shares were valued at $2.25 per share, the believed market
value for free trading shares at the time of issue. The amount was expensed as general and administrative expense. The shares of
common stock were issued out of Treasury Stock and reduced the amount of the Company's common stock held in Treasury from 46,668
to 36,668 shares.

Effective August 1, 2011, the Company issued 10,000 shares of restricted
common stock (5,000 shares to each of two individuals) pursuant to an employment package. The shares were valued at $1.70 per share,
the believed market value for free trading shares at the time of issue. The amount was expensed as general and administrative expense.
The shares of common stock were issued out of Treasury Stock and reduced the amount of the Company's common stock held in Treasury
from 36,668 to 26,668 shares.

Effective December 30, 2011, the Company issued 10,000 shares of
restricted common stock to a key employee pursuant to an employment package. The shares were valued at $1.70 per share, the believed
market value for free trading shares at the time of issue. The amount was expensed as general and administrative expense. The shares
of common stock were issued out of Treasury Stock and reduced the amount of the Company's common stock held in Treasury from 26,668
to 16,668 shares.

The Company has not approved nor authorized any standing repurchase
program for its common stock.

During the fourth quarter of the fiscal year ended December 31, 2012,
the Company made the following repurchases of its common stock:

Effective October 30, 2012, the Company repurchased 700,000
shares of its common stock for a purchase price of $1,491,000 or $2.13 per share.

On December 18, 2012, the Company repurchased 24,534 shares
of its common stock for a purchase price of $36,801 or $1.50 per share.

The repurchased shares are held as Treasury Stock.

8. INCOME TAXES

The Company accounts for income taxes pursuant to ASC Topic 740-10,
"Accounting for Income Taxes". ASC Topic 740-10 utilizes the liability method of computing deferred income taxes.

In connection with the Plan discussed in Note 1, the Company agreed
to pay, in cash, to Exploration's unsecured creditors, as defined, one-half of the future reductions of Federal income taxes which
were directly related to any allowed carryovers of Exploration's net operating losses and investment tax credits. Such payments
are to be made on a pro-rata basis. Amounts incurred under this agreement, which are considered contingent consideration, totaled
$ -0-, $ -0-, and $ -0- in 2012, 2011 and 2010, respectively. As of December 31, 2012 the Company has not received a ruling from
the Internal Revenue Service concerning the net operating loss and investment credit carryovers. Until the tax savings which result
from the utilization of these carry-forwards is assured, the Company will not pay to Exploration's unsecured creditors any of the
tax savings benefit. As of December 31, 2012, the Company owes $97,000 to Exploration's unsecured creditors.

-59-

In calculating tax savings benefits described above, consideration
was given to the alternative minimum tax, where applicable, and the tax effects of temporary differences, as shown below:

Income tax differed from the amounts computed by applying an effective
United States federal income tax rate of 34% to pretax income in 2012, 2011 and 2010 as a result of the following:

2012

2011

2010

Computed expected tax expense (benefit)

$999,000

$449,000

$42,000

Miscellaneous timing differences

related to book and tax depletion

differences and the expensing of

intangible drilling costs

(752,000)

(678,000)

(139,000)

Expected Federal income tax expense (benefit)

$247,000

$(229,000)

$(97,000)

Income tax expense (benefit) for the years ended December 31, 2012, 2011 and 2010 consisted of the following:

2012

2011

2010

Federal income taxes (benefit)

$247,000

$(229,000)

$(97,000)

State income taxes

-

-

-

Current income tax provision (benefit)

$247,000

$(229,000)

$(97,000)

Deferred income taxes reflect the effects of temporary differences
between the tax bases of assets and liabilities and the reported amounts of those assets and liabilities for financial reporting
purposes. Deferred income taxes also reflect the value of investment tax credits and an offsetting valuation allowance. The Company's
total deferred tax assets and corresponding valuation allowance at December 31, 2012 and 2011 consisted of the following:

December 31,

2012

2011

Deferred tax assets

Depreciation, depletion and amortization

770,000

238,000

Other, net

7,000

7,000

Total

777,000

245,000

Deferred tax liabilities

Expired leasehold

(67,000)

(335,000)

Intangible drilling costs

(2,200,000)

(2,716,000)

Depreciation

(348,000)

-

Net deferred tax liability

$(1,838,000)

$(2,806,000)

-60-

9. CASH FLOW INFORMATION

The Company does not consider any of its assets, other than cash
and certificates of deposit shown as cash on the balance sheet, to meet the definition of a cash equivalent.

Net cash provided by operating activities includes cash payments for the following:

2012

2011

2010

Interest expense

$29,000

$55,000

$84,000

Income taxes

50,000

170,000

-

Excluded from the Consolidated Statements of Cash Flows were the effects of certain non-cash investing and financing activities, as follows:

2012

2011

2010

Addition (Reduction) of Oil & Gas properties

by recognition of asset retirement obligation

$(36,000)

$57,000

$45,000

10. EARNINGS PER SHARE

Earnings per share ("EPS") are calculated in accordance
with ASC Topic 260-10, "Earnings per Share", which was adopted in 1997 for all years presented. Basic EPS is computed
by dividing income available to common shareholders by the weighted average number of common shares outstanding during the period.
The adoption of ASC Topic 260-10 had no effect on previously reported EPS. Diluted EPS is computed based on the weighted number
of shares outstanding, plus the additional common shares that would have been issued had the options outstanding been exercised.

11. CONCENTRATIONS OF CREDIT RISK

Subsequent to December 31, 2012, FDIC Deposit insurance coverage
changed. As scheduled, the unlimited insurance coverage for noninterest-bearing transaction accounts provided under the Dodd-Frank
Wall Street Reform and Consumer Protection Act expired on December 31, 2012. Deposits held in non-interest-bearing transaction
accounts are now aggregated with any interest-bearing deposits the owner may hold in the same ownership category, and the combined
total insured up to at least $250,000.

Beginning January 1, 2013, noninterest-bearing transaction accounts
will no longer be insured separately from depositors’ other accounts at the same institution. Instead, noninterest-bearing
transaction accounts will be added to any of a depositor’s other accounts in the applicable ownership category, and the aggregate
balance insured up to at least the Standard Minimum Deposit Insurance Amount (SMDIA) of $250,000, per depositor, at each separately
chartered institution.

As of December 31, 2012 the Company had approximately $3,202,000
in checking and money market accounts at one bank, and approximately $3,058,000, which includes
approximately $400,000 of long-term certificates of deposit, at a second bank. The Company also had approximately $3,295,000,
including $400,000 of short-term certificates of deposit and $800,000 of long-term certificates of deposit invested at six other
banking institutions. Cash amounts on deposit at these institutions exceeded current per account FDIC protection limits by approximately
$3,325,000.

If the post 2012 FDIC coverage had been in effect at December 31,
2012, the Company’s amounts on deposit would have exceeded the new FDIC protection limits by approximately $4,760,000.

-61-

Most of the Company's business activity is located in Texas. Accounts
receivable as of December 31, 2012 and 2011 are due from both individual and institutional owners of joint interests in oil and
gas wells as well as purchasers of oil and gas. A portion of the Company's ability to collect these receivables is dependent upon
revenues generated from sales of oil and gas produced by the related wells.

12. FINANCIAL INSTRUMENTS

The estimated fair value of the Company's financial instruments at
December 31, 2012 and 2011 follows:

2012

2011

Carrying Amount

Fair Value

Carrying Amount

Fair Value

Cash

$7,151,000

$7,151,000

$6,695,000

$6,695,000

Short-term certificates

400,000

400,000

400,000

400,000

Long-term certificates

1,200,000

1,200,000

1,200,000

1,200,000

Accounts receivable

2,155,000

2,155,000

1,609,000

1,609,000

The fair value amounts for each of the financial instruments
listed above approximate carrying amounts due to the short maturities of these instruments.

13. COMMITMENTS AND CONTINGENCIES

In connection with the Plan of Reorganization discussed in Note 1,
the Company agreed to pay, in cash, to Exploration's unsecured creditors, as defined, one-half of the future reduction of Federal
income taxes which were directly related to any allowed carryovers of Exploration's net operating losses and investment tax credits
existing at the time of the reorganization.

The Company's oil and gas exploration and production activities are
subject to Federal, State and environmental quality and pollution control laws and regulations. Such regulations restrict emission
and discharge of wastes from wells, may require permits for the drilling of wells, prescribe the spacing of wells and rate of production,
and require prevention and clean-up of pollution.

Although the Company has not in the past incurred substantial costs
in complying with such laws and regulations, future environmental restrictions or requirements may materially increase the Company's
capital expenditures, reduce earnings, and delay or prohibit certain activities.

At December 31, 2012 the Company has acquired bonds and letters of
credit issued in favor of various state regulatory agencies as mandated by state law in order to comply with financial assurance
regulations required to perform oil and gas operations within the various state jurisdictions.

The Company has seven, $5,000 single-well
bonds totaling $35,000 and one $10,000 single well bond with an insurance company, for wells the Company operates in Alabama. The
$5,000 bonds are written for a three year period and the $10,000 bond is written for a one year period.

The Company has 10 letters of credit from
a bank issued for the benefit of various state regulatory agencies in Texas, New Mexico, Oklahoma, and Louisiana, ranging in amounts
from $10,000 to $50,000 and totaling $298,000. These letters of credit have expiration dates that range from January 1, 2013 through
January 16, 2015 and are fully secured by funds on deposit with the bank in business money market accounts.

-62-

14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION

Certain information about the Company's operations for the years
ended December 31, 2012, 2011 and 2010 follows.

Sale of Oil & Gas Properties

In March, 2010, the Company sold its working interest and operations
in the Robertson 20-12 well located in Lamar County, Alabama to an unrelated party for $5,000 in cash.

In December, 2012, the Company sold its working interest effective
October 1, 2012, in 29 non-operated properties located in Palo Pinto, Wise, Jack, and Parker Counties, Texas to the operator of
the wells for a gross sales price of $165,000.

Dependence on Customers

The following is a summary of significant purchasers / operators
(listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period
ended December 31, 2012:

Purchaser / Operator

2012

2011

2010

Shell Trading (US) Company

15%

20%

7%

Pruet Production Co.

9%

0%

0%

Enbridge Energy Partners

9%

22%

26%

Targa Midstream Service, LIM

8%

4%

3%

Halcon Resources Operating, Inc.

7%

0%

0%

Eastex Crude Company

6%

7%

7%

Crosstex Gulf Coast Mktg

5%

11%

16%

Panther Energy Company, LLC

4%

0%

0%

Gulfmark Energy, Inc.

4%

3%

0%

HollyFrontier Refining & Marketing LLC

3%

2%

3%

Petromax Operating Co., Inc.

3%

0%

0%

Sunoco Partners Marketing

3%

1%

1%

Encana Oil & Gas (USA), Inc.

3%

0%

0%

Enterprise Crude Oil, LLC

2%

5%

5%

Enervest Operating, LLC

2%

0%

0%

Sklar Exploration Co., LLC

2%

0%

0%

ETC Texas Pipeline

2%

2%

2%

Oil and gas is sold to approximately
100 different purchasers under market sensitive, short-term contracts computed on a month to month basis.

Except as set forth above, there are no other customers of the Company
that individually accounted for more than two percent of the Company's oil and gas revenues during the three years ended

December 31, 2012.

The Company currently has no hedged contracts.

-63-

Certain revenues, costs and expenses related to the Company's oil
and gas operations are as follows:

Year Ended December 31,

2012

2011

2010

Capitalized costs relating to oil and gas

producing activities:

Unproved properties

$2,267,000

$2,242,000

$2,064,000

Proved properties

20,555,000

18,153,000

15,820,000

Total capitalized costs

22,822,000

20,395,000

17,884,000

Accumulated amortization

(10,744,000)

(9,161,000)

(8,129,000)

Total capitalized costs, net

$12,078,000

11,234,000

$9,755,000

Year Ended December 31,

2012

2011

2010

Costs incurred in oil and gas property

acquistions, exploration and development:

Acquistion of properties

$685,000

$303,000

$458,000

Development costs

1,742,000

2,208,000

2,346,000

Total costs incurred

$2,427,000

$2,511,000

$2,804,000

Year Ended December 31,

2012

2011

2010

Results of operations from producing activities:

Sales of oil and gas

$9,999,000

$8,000,000

$6,302,000

Production costs

3,521,000

3,253,000

2,613,000

Amortization of oil and gas properties

1,583,000

1,032,000

916,000

Total production costs

5,104,000

4,285,000

3,529,000

Total net revenue

$4,895,000

$3,715,000

$2,773,000

Year Ended December 31,

2012

2011

2010

Sales price per equivalent Mcf

$7.88

$7.80

$6.22

Production costs per equivalent Mcf

$2.78

$3.17

$2.58

Amortization per equivalent Mcf

$1.25

$1.01

$0.90

-64-

Year Ended December 31,

2012

2011

2010

Results of operations from gas gathering

and equipment rental activities:

Revenue

$145,000

$172,000

$179,000

Operating expenses

26,000

25,000

33,000

Depreciation

-

1,000

1,000

Total costs

26,000

26,000

34,000

Total net revenue

$119,000

$146,000

$145,000

15. BUSINESS SEGMENTS

The Company's three business segments are (1) oil and gas exploration,
acquisition, production and operations, (2) transportation and compression of natural gas, and (3) commercial real estate investment.
Management has chosen to organize the Company into the three segments based on the products or services provided. The following
is a summary of selected information for these segments for the

three-year period ended December 31, 2012:

Year Ended December 31,

2012

2011

2010

Revenues: (1)

Oil and gas exploration, production

$10,357,000

$8,289,000

$6,621,000

and operations

Gas gathering, compression and

145,000

172,000

179,000

equipment rental

Real estate rental

242,000

436,000

448,000

$10,744,000

$8,897,000

$7,248,000

Year Ended December 31,

2012

2011

2010

Depreciation, depletion, and

amortization expense:

Oil and gas exploration, production

$1,594,000

$1,050,000

$940,000

and operations

Gas gathering, compression and

-

1,000

1,000

equipment rental

Real estate rental

53,000

101,000

101,000

$1,647,000

$1,152,000

$1,042,000

-65-

Year Ended December 31,

2012

2011

2010

Income from operations:

Oil and gas exploration, production

$5,201,000

$3,952,000

$3,020,000

and operations

Gas gathering, compression and

119,000

146,000

145,000

equipment rental

Real estate rental

4,000

110,000

101,000

5,324,000

4,208,000

3,266,000

Corporate and other (2)

(1,665,000)

(2,455,000)

(2,819,000)

Consolidated net income

$3,659,000

$1,753,000

$447,000

Year Ended December 31,

2012

2011

2010

Identifiable assets net of DDA:

Oil and gas exploration, production

and operations

$12,126,000

$11,289,000

$9,829,000

Gas gathering, compression and

equipment rental

(1,000)

Real estate rental

1,615,000

1,667,000

1,767,000

13,741,000

12,955,000

11,596,000

Corporate and other (3)

10,912,000

10,324,000

9,181,000

Consolidated total assets

$24,653,000

$23,279,000

$20,777,000

Note (1): All reported revenues are from external customers.

Note (2): Corporate and other includes general and administrative
expenses,

other non-operating income and expense and income taxes.

Note (3): Corporate and other includes cash, accounts and notes receivable,

inventory, other property and equipment and intangible assets.

16. SUPPLEMENTARY INCOME STATEMENT INFORMATION

The following items were charged directly to expense:

Year Ended December 31,

2012

2011

2010

Maintenance and repairs

$11,000

$15,000

$15,000

Production taxes

487,000

371,000

256,000

Taxes, other than payroll and income taxes

9,000

11,000

4,000

-66-

17. QUARTERLY DATA (UNAUDITED)

The table below reflects selected quarterly information for the years
ended December 31, 2012, 2011 and 2010.

Year Ended December 31, 2012

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Revenue

$2,356,000

$2,940,000

$2,561,000

$4,249,000

Expense

(1,717,000)

(2,055,000)

(1,928,000)

(3,468,000)

Operating income (loss)

639,000

885,000

633,000

781,000

Current tax (provision) benefit

(78,000)

(66,000)

(3,000)

(100,000)

Deferred tax (provision) benefit

181,000

199,000

90,000

498,000

Net income (loss)

$742,000

$1,018,000

$720,000

$1,179,000

Earnings (loss) per share of

common stock

Basic and diluted

$0.10

$0.13

$0.09

$0.17

Year Ended December 31, 2011

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Revenue

$2,620,000

$2,077,000

$2,040,000

$2,603,000

Expense

(1,770,000)

(1,805,000)

(1,774,000)

(2,670,000)

Operating income (loss)

850,000

272,000

266,000

(67,000)

Current tax (provision) benefit

(79,000)

113,000

(12,000)

207,000

Deferred tax (provision) benefit

37,000

(104,000)

10,000

260,000

Net income (loss)

$808,000

$281,000

$264,000

$400,000

Earnings (loss) per share of

common stock

Basic and diluted

$0.10

$0.04

$0.03

$0.06

Year Ended December 31, 2010

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Revenue

$1,968,000

$1,765,000

$1,831,000

$2,092,000

Expense

(1,523,000)

(1,631,000)

(1,810,000)

(2,569,000)

Operating income (loss)

445,000

134,000

21,000

(477,000)

Current tax (provision) benefit

(31,000)

(63,000)

244,000

(53,000)

Deferred tax (provision) benefit

(59,000)

76,000

(39,000)

249,000

Net income (loss)

$355,000

$147,000

$226,000

$(281,000)

Earnings (loss) per share of

common stock

Basic and diluted

$0.05

$0.02

$0.03

$(0.04)

-67-

18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

The Company’s net proved oil and natural gas reserves as of
December 31, 2012, 2011, and 2010 have been estimated by Company personnel.

All estimates are in accordance generally accepted petroleum engineering
and evaluation principles and definitions and with guidelines established by the Securities and Exchange Commission. All of the
Company’s reserves are located in the United States of America and accounted for under one cost center.

Our policies and practices regarding internal control over the estimating
of reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values
in compliance with the U.S. Securities and Exchange Commission (“SEC”) regulations and accounting principles generally
accepted in the United States of America. We maintain an internal staff of petroleum engineers and geosciences professionals who
work closely with the accounting and financial departments to insure the integrity, accuracy and timeliness of data used in the
estimation process. The data used in our reserve estimation process is based on historical results for production, oil and natural
gas prices received, lease operating expenses and development costs incurred, ownership interest and other required data. Historical
oil and gas prices, lease operating expenses, and ownership interests are provided by and verified by the Company’s accounting
department.

The Petroleum Engineer responsible for the supervision and preparation
of the Company’s internally generated reserve report has a Bachelor of Science degree in Petroleum Engineering from a major
university and has experience in preparing economic evaluations and reserve estimates. He meets the requirements regarding qualifications,
objectivity and confidentiality set forth in the Standards Pertaining to the Engineering and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers.

The Company has established a written internal control procedure
to verify that the data entered into our engineering evaluation software is complete and correct. These internal control procedures
establish the source of the data both internally and externally, the personnel that will collect the data and testing of the data
collected to ensure its accuracy.

The following reserve estimates were based on existing economic and
operating conditions. Oil and gas prices for 2012, 2011, and 2010 were calculated using a 12-month average price, calculated as
the un-weighted arithmetic average of the first-day-of-the month price for each month of each year. Operating costs, production
and ad valorem taxes and future development costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities
of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve
data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed
as the current market value of the Company's oil and gas reserves or the costs that would be incurred to obtain equivalent reserves.

The Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves ("Standardized Measures") does not purport to present the fair
market value of a company's oil and gas properties. An estimate of such value should consider, among other factors, anticipated
future prices of oil and gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves
and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially
from new discoveries, are inherently imprecise and subject to substantial revision.

Reserve estimates were prepared in accordance with standard Security
and Exchange Commission guidelines. The future net cash flow for 2012, 2011, and 2010, was computed using a 12-month average price,
calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. Lease operating
costs, compression, dehydration, transportation, ad valorem taxes, severance taxes, and federal income taxes were deducted. Costs
and prices were held constant and were not escalated over the life of the properties. No deduction has been made for interest,
or general corporate overhead. The annual discount of estimated future cash flows is defined, for use herein, as future cash flows
discounted at 10% per year, over the expected period of realization.

-69-

Proved Developed Reserves were calculated based on Decline Curve
Analysis on 77 operated wells and 86 non-operated wells. Materially insignificant
operated and non-operated wells were excluded from the reserve estimate.

The Company emphasizes that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information becomes available. It is reasonably possible that,
because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash
inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties,
or any combination of the above may be increased or reduced in the near term. If reduced, the carrying amount of capitalized oil
and gas properties may be reduced materially in the near term.

Two story multi-tenant garden office building with sub-grade parking garage located in Dallas, Texas

(b)

$ 688,000

$ 1,298,000

$ 282,000

Gross amounts at which carried at close of year

Land

Buildings

Total

AccumulatedDepreciation

Life on whichDepreciationCalculated

DateAcquired

$ 688,000

$ 1,580,000

$ 2,268,000

$ 653,000

(a)

12/27/2004

Notes to Schedule III

(a) See Footnote 2 to the Financial Statements outlining depreciation methods and lives.

(b) See description of notes payable in Footnote 5 to the Financial Statements outlining the terms and provisions of the acquisition loan for the building.

-72-

(c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2012 are as follows

Investments inReal Estate

AccumulatedDepreciation

Balance, December 31, 2005

$ 1,986,000

$ 49,000

Acquisitions

210,000

Depreciation expense

71,000

Balance, December 31, 2006

2,196,000

120,000

Acquisitions

34,000

Depreciation expense

84,000

Balance, December 31, 2007

2,230,000

204,000

Acquisitions

38,000

Depreciation expense

96,000

Balance, December 31, 2008

2,268,000

300,000

Acquisitions

Depreciation expense

100,000

Balance, December 31, 2009

2,268,000

400,000

Acquisitions

Depreciation expense

101,000

Balance, December 31, 2010

2,268,000

501,000

Acquisitions

Depreciation expense

100,000

Balance, December 31, 2011

2,268,000

601,000

Acquisitions

Depreciation expense

52,000

Balance, December 31, 2012

$ 2,268,000

$ 653,000

-73-

Exhibit 21

SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES

Subsidiaries of the Registrant

Spindletop Drilling Company, incorporated September 5, 1975, under
the laws of the State of Texas, is a wholly owned subsidiary of the Registrant.

Prairie Pipeline Co. incorporated June 22, 1983, under the laws of
the State of Texas, is a wholly owned subsidiary of Registrant.

-74-

Exhibit 31.1

CERTIFICATIONS

I, Chris G. Mazzini, certify that:

1. I have reviewed this report on Form 10-K of Spindletop Oil
& Gas Co.;

2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known
to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation;
and

(d)

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee
of registrant's Board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information;
and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's
internal controls.

Date: April 15, 2013

By:/s/ Chris G. Mazzini

Chris G. Mazzini

President, Principal Executive Officer

-75-

Exhibit 31.2

CERTIFICATIONS

I, Robert E. Corbin, certify that:

1. I have reviewed this report on Form 10-K of Spindletop Oil
& Gas Co.;

2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and
internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known
to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation;
and

(d)

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee
of registrant's Board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information;
and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's
internal controls.

Date: April 15, 2013

By:/s/ Robert E. Corbin

Robert E. Corbin

Controller, Principal Financial and Accounting Officer

-76-

Exhibit 32

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002

In connection with the Annual Report of Spindletop Oil & Gas
Co. (the “Company”), on Form 10-K for the year ended December 31, 2012 as filed with the Securities Exchange Commission
on the date hereof (the “Report”), the undersigned Principal Executive Officer and Principal Financial and Accounting
Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002, that:

The Report fully complies with the requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly
presents, in all material respects, the financial condition and result of operations of the Company.

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